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Group
MRO’s NERC Standards Review Subcommittee (NSRS)
Joseph DePoorter
Midwest Reliability Organization
No
The NSRS feels additional changes are needed. The functional testing requirement should be altered or removed as it increases the amount of hands-on involvement and the opportunity for human error related outages to occur, thereby introducing a greater risk to decrease system reliability. As noted on p. 8 in the supplementary reference document, “Experience has shown that keeping human hands away from equipment known to be working correctly enhances reliability.” By removing circuits from service on the proposed timelines for functional testing, the chance for human error is greater than a mis-operation from faulty wiring. Alternatively, entities may choose to schedule more planned outages to conduct their functional testing in order to limit the risk of unplanned outages resulting from human error. Under this scenario, more elements will be scheduled out of service on a regular basis, thereby reducing transmission system availability and weakening the system making it more challenging to withstand each subsequent contingency (N-1). Thus testing an in-tact system is more desirable than taking it out of service for testing. While the SDT has included language in the draft standard to use fault analysis to complete maintenance obligations, in practicality, this option does not offer any relief to taking outages to perform functional tests. Nearly all BES circuit breakers are equipped with dual trip coils. Identifying which trip coil operated for a fault only covers the one trip coil. Functional tests would still be needed on the other. The likelihood of having multiple trips on a given line in the course of several years is very low. Given it can take a year to schedule some outages; planning maintenance with random faults is unpractical and will create unacceptable risk to compliance violations. A better approach is to use the basis in schedule A, but extend this to cover the entire protection schemes. The document should establish target goals for mis-operation rates (dependability and security). This would allow the utilities to develop cost effective programs to increase reliability. The utilities would have incentives to replace poorly performing communications systems; they would be able to quantify the value of upgrading relay systems.
No
The NSRS disagrees with the VRFs as specified in the standard. R1 VRF would more likely be classified as “medium” and R2 through R4 should be classified as a “High” VRF.
No
The NERC standard assigns a retention period for the two most recent performances of maintenance activity which implies two intervals of documentation being maintained. The NSRS does not agree that requiring all data for two full cycles is warranted. The volume and length of data retention is unreasonable. The NSRS recommends that the entity retain the last test date with the associated data, plus the prior cycle test date only without retaining the test data.
Yes
 
Yes
 
No
The FAQs are helpful, however, with the revised standard as written, The NSRS has issues with the answers provided. Please refer to Question #7 for areas of concern.
The NSRS does not support the existing 2nd Draft of PRC-005-2 Standard because it is our opinion that: • There is a high probability that system reliability will be reduced with this revised standard. • The utility industry is in the business of keeping the lights on, but these requirements will force the industry to take customers out of service in order to fulfill these requirements. A possible solution is to increase the test intervals, set performance targets, test set on a basis of past performance, etc. • The number of unplanned outages due to human error will increase considerably. • The requirement of a complete functional trip test will reduce the level of reliability and all levels of the BES to include distribution systems. • Availability of the BES will be reduced due to an increased need to schedule planned outages for test purposes (to avoid unplanned outages due to human error). • To implement this standard, an entity will need to hire additional skilled resources that are not readily available. (May require adjustments to the implementation timeline.) • The cost of implementing the revised standard will approximately double our existing cost to perform this work. Requests that relevant reliability performance data (based on actual data and/or lessons learned from past operating incidents, Criteria for Approving Reliability Standards per FERC Order 672) be provided to justify the additional cost and reliability risks associated with functional testing. Under a Performance-Based Program, what happens if the population of components drops below 60 (as all will eventually)? Is there an implementation period to default to TBM? Please clarify. In R1, the statement “or are designed to provide protection for the BES” re-opens the argument about transformer protection or breaker failure protection for transformer high-side breakers tripping BES breakers being included in the transmission protection systems. Also, for Table 1b “Verify that each breaker trip coil, each auxiliary relay, and each lockout relay is electrically operated within this time interval” should be changed from a 6 year interval to a 12 year interval similar to the relay input and outputs. Experience has shown that these both have very similar reliability. The standard as currently drafted raises concern as it relates to the identification of all Protection System components, particularly those with associated communications equipment. In the case of leased lines, a utility would be expected to maintain equipment they do not own. Recommend revising the standard to consider maintenance activities on a communications channel basis in which intermediate device functioning can be verified by sending a signal from one relay to another. Clarification should be given as to the reason for stating control circuitry separately, such as in “Control and trip circuits”. As currently stated, this implies that close circuit DC paths are now subject to a protection system maintenance program when reclosing and closing of breakers have never before been considered part of a Protection System. Statements 3 (For microprocessor relays, check the relay inputs and outputs that are essential to proper functioning of the Protection System. )and 6(Verify correct operation of output actions that are used for tripping. in Table 1b for Protective Relays essentially address the same issue. Please clarify if these are addressing the same issue or not. If the purpose is to describe the functionality of the protection system, that should be covered under another section in the table, such as DC circuitry. How one identifies a voltage and current sensing input is not well defined. In most cases, this should already be identified with the relay. Also, the scope of detail required is ambiguous. Would individual cables, terminal blocks, etc. need to be identified as would be implied by “associated circuitry”? Please clarify. The NSRS recommends that individual cables, terminal blocks, etc are not included in this program. Recommend removing “proper functioning of” from the maintenance activities for voltage and current sensing inputs in Table 1b. A utility is not verifying the functionality of the signal(s), they are verifying the signals themselves. Any functioning of the signals, which is related to ensuring proper relay interpretation, would be covered under the protective relay section. In general, has thought been put into the possibility of degrading reliability by implementing such a rigorous maintenance program? To implement such a program, the number of scheduled outages would greatly increase resulting in scheduling conflicts that will increase, as well as degrading system conditions by taking lines, transformers, etc. out of service. Because of past design practices many of the requirements for maintenance will only be able to be performed by lifting wires to isolated trip paths. Potential error is introduced anytime a wire is lifted, especially numerous wires, by means of ensuring they are put back in the correct place. Redundancy is one thing that has been implemented in great detail throughout the history of protection systems to ensure that they work as intended. Diligent commissioning may need to be given its due credit.
Group
Northeast Power Coordinating Council
Guy Zito
Northeast Power Coordinating Council
No
Clarification is needed for “to a location where action can be taken”. Some examples in the FAQ will help in this clarification. What type of documentation is required to show compliance that maintenance correctable issue has been reported? Clarify the removal of requirement (see redline version, third row of Table 1a) for testing of unmonitored breaker trip coils. Is it the intention of the SDT to remove a requirement that would drive the industry to install TC monitors on breakers to improve reliability? UFLS/UVLS DC control and trip circuits (Rows 5 and 6 of Table 1a) – Due to the distributed nature of this program, random failures to trip are not impactive to the overall operation of the UFLS protection. There should be no requirement to check the DC portion of these protections any more often than the DC circuit checks associated with that LV breaker. Since it is clear the requirement does not include the need to trip the breakers why the need to check the trip paths? Deletion of this requirement leaves the requirement to check only the relays and relay trip outputs from the protections every 6 years (or as often as the protective relay component type). Should the maintenance activities for “UVLS and UFLS relays that comprise a protection scheme distributed over the power system” not be the same as “Protective Relays”? V and I sensing to relays have a 12 year Maximum Maintenance Interval listed. It is good work practice to have this activity done the same time as maintenance activities associated with relay maintenance. What is the basis for the various Maximum Maintenance Intervals listed in Table 1a? From page 12 of the redline version, for "Station dc Supply (used only for UFLS and UVLS)", is the requirement applicable to distribution substations only? For “Control and trip circuits with unmonitored solid-state trip or auxiliary contacts (UFLS/UVLS Systems only)” under Maintenance Activities - the word “complete: may be removed as it requires to actually trip the breakers. The sentence that tripping of the circuit breakers is not required contradicts with the word “complete”. More specifics are required to spell out the adequate testing e.g. up to the lockout with the trip paths isolated etc. See Page 12 of the redline version. For “Station dc Supply” having 18 calendar months as the Maximum Maintenance Interval, a battery has a 20 year life. IEEE standard PM is on a quarterly basis. What is the basis of the 18 calendar month interval? See page 12 of the redline version. For “Associated communications systems” with a Maximum Maintenance Interval of 6 Calendar years, why is this required? The text "Verify proper functioning of communications equipment inputs and outputs that are essential to proper functioning of the Protection System. Verify the signals to/from the associated protective relay(s)" seems sufficient to ensure reliability. See page 15 of the redline version. For “Relay sensing for Centralized UFLS or UVLS systems UVLS and UFLS relays that comprise a protection scheme distributed over the power system” under maintenance activities, clarify “overlapping segments”. What is the specified interval? Is actual breaker tripping required? See page 15 of the redline version. On the row for Associated communications systems in Table 1c, in the Level 3 Monitoring Attributes for Component column, suggest a change in wording to: Evaluating the performance and quality of the channel as well as the performance of any interface to connected protective relays and alarming if the channel/protective relay connections do not meet performance criteria. In Table 1c it is required to report the detected maintenance correctable issues within 1 hour or less to a location where action can be taken to initiate resolution of that issue. Even for a fully monitored protection system component it can be difficult to report the action in 1 hour. A 24 hour period for both Level 2 and Level 3 reporting of maintenance correctable issues is recommended.
Yes
 
No
Clarification is needed for “on-site audit” – does it include audits by any of the following - NPCC/NERC/FERC. Several small entities do not have on-site audits and participate in off-site audits. Hence, suggest deleting “on-site” from the requirement. Further clarification is required to the Data Retention section to coordinate with the statement in FAQ (Section IV.d p. 22 redline). Suggest the following revised Data Retention requirement consistent with the statement and example given in FAQ: “The Transmission Owner, Generator Owner, and Distribution Provider shall each retain at least two maintenance test records or statistical data to demonstrate compliance with test interval required for each distinct maintenance activity for the Protection System components. The Compliance Enforcement Authority shall keep the last periodic audit report and all requested and submitted subsequent compliance records.”
No
R4 under Severe VSL mentions – Entity has failed to initiate resolution of maintenance-correctable issues. What proof will satisfy the requirement that the entity has initiated the resolution? R1 under Severe VSL – Move the first criteria “The entity’s PSMP failed to address one or more of the type of components included in the definition of ‘Protection System’” under High VSL since this criteria cannot have the same VSL level as “Entity has not established a PSMP”.
No
There is no guidance on how to calculate the total number of components and thus, the percentages under different severity levels. FAQ provides some insight into how an entity can count components. However; an example in the reference document will provide clarity. Page 7 of the redline version of Supplemental Reference – bullet 1 under Maintenance Services, paragraph 2 states “ If specific protection scheme components have demonstrated correct performance within specifications, the maintenance test time clock is reset for those components.” Resetting the time clock will make tracking difficult (unless entities have a sophisticated automated tool for tracking). Another option where an entity can take credit for a correct performance within specifications at the time of the maintenance cycle should be included.
Yes
 
UFLS systems by design can suffer random failures to trip. A requirement should exist that stipulates to perform maintenance on the UFLS relay as their failure to operate may affect numerous distribution level feeders. However maintenance on associated DC schemes connected to the devices should only be done on the same frequency as maintenance on the relevant interrupting devices. Consideration should be given to exempting schemes that have a maintenance program in place on those distribution level devices from PRC-005 Standard-specified maintenance intervals. Such Standard-specified intervals could apply to interrupting devices that have no maintenance program in place. This standard is overly prescriptive. Owners of protection system equipment establish maintenance procedures and timelines based on manufacturers’ recommendations and experiences to ensure reliability. Maintenance intervals change with improved practices and equipment designs, and whenever that occurs PRC-005 will have to go through the revision process, which would be frequent and unnecessary if the standard were more general.
Group
Southern Company Transmission
JT Wood
Southern Company
No
1)Comment on Control Circuitry – Below in Figure 1 is a previous version of Table 1. It clearly shows 3 levels of monitoring for Control Circuitry. For Unmonitored schemes such as EM, SS, unmonitored MP relays, you must do a complete functional trip test every 6 years. For partially monitored schemes such as MP relays with continuous trip coil/circuit monitoring, you must do a complete functional trip test every 12 years. For fully monitored schemes where all trip paths are monitored, you do not have to trip test the scheme but you still have to operate the breaker trip coils, EM aux/lockout relays every 6 years. This is very clear and reasonable. The latest version of Table 1 is not very clear or reasonable. The previous Partially Monitored control circuit monitoring requirements were deleted and the Fully Monitored control circuit monitoring requirements were moved to Partially Monitored requirements. We are not sure why this major change in philosophy was made?? This makes all of our MP relay control schemes that continuously monitor trip coils/circuits fall into the unmonitored category and therefore requires a 6 year full functional trip test. For a scheme that monitors 99+% of the control scheme (and probably 100% of the control scheme that actually has problems) to be considered Unmonitored does not seem logical or reasonable to us. This puts these “highly monitored” schemes in the same category and requires the same maintenance requirements / intervals as EM relays with no alarms whatsoever. This also seems to contradict the intent of the following statement from the Supplementary Reference doc on page 9: Level 2 Monitoring (Partially Monitored) Table 1b This table applies to microprocessor relays and other associated Protection System components whose self-monitoring alarms are transmitted to a location (at least daily) where action can be taken for alarmed failures. The attributes of the monitoring system must meet the requirements specified in the header of the Table 1b. Given these advanced monitoring capabilities, it is known that there are specific and routine testing functions occurring within the device. Because of this ongoing monitoring hands-on action is required less often because routine testing is automated. However, there is now an additional task that must be accomplished during the hands-on process – the monitoring and alarming functions must be shown to work. Recommendation - Please consider going back to the previous table as shown below in Figure 1. It seems much clearer and reasonable. Feel free to convert the old wording to the latest wording. Figure 1 - Previous Table – Control Circuitry See Figure 1 in email documentation sent to Al McMeekin. Current Table – Control Circuitry (see pdf file) See pdf file PRC-005-2_clean_20 10June88131418.pdf in email documentation sent to Al McMeekin. 2) Comments: The comments below are grouped by component type. The following (5) comments pertain to the maintenance intervals for protective relays: 1.Is the “verify acceptable measurement of power system input values” activity listed in the protective relay 6 year interval in Table 1a the same activity as the 12-year activity for Voltage and Current Sensing Inputs in the same table? 2.Please clarify the meaning of “check the relay inputs and outputs” that are specified to be checked for microprocessor relays at the following table locations: the protective relay 6 year interval in Table 1a, the protective relay 12-year interval in Table 1b. Is this referring to a check of the relay internal input recognition and output control ending at the relay case terminals, or is this referring to a check extending to the source (and target) of all inputs and outputs to the relay? The latter interpretation results in a repeat of the maintenance required for dc control circuitry. 3.Are the second, third, and fourth maintenance activities in the Table 1a Protective Relay, 6-year row those activities that apply to microprocessor relays? If so, we suggest rewording these items as follows: For microprocessor relays, verify that the settings are as specified, check the relay digital inputs and outputs that are essential to proper functioning of the Protection System, and verify acceptable measurement of power system analog input values.” 4.Please clarify the meaning of “Verify proper functioning of the relay trip contacts” found in protective relays with trip contacts 12 year interval in Table 1c. Is this verification a check of the relay internal contact to the relay case terminals or is this meant to be a trip check functional test? This category of component does not appear in table 1a or 1b. Should it? Is this activity the same as the protective relay Table 1b maintenance activity “output actions used for tripping”? If so, please make the wording match exactly to clarify. 5.Table 1c introduces the use of “Continuous” Maximum Maintenance Intervals. This is inconsistent with the Table 1a and Table 1b usage of the interval. In Tables 1a and 1b this interval is used to describe the maximum time frame within which the activities shown in “Maintenance Activities” must be completed. The table column “Maintenance Activities” has been used to identify those activities which must be performed in addition to those accomplished by the monitoring attributes. To maintain consistency in use of the interval and activity columns of Tables 1a, 1b, and 1c, each entry that uses the “Continuous” interval should be changed to N/A and the Maintenance Activities should be changed to either “No additional activities required” or “None, due to continuous automatic verification of the status of the relays and alarming on change of settings” [example given for Table 1c, Protective Relays] The following (8) comments apply to Maintenance Tables 1a, 1b, and 1c for Station DC supplies. 1)In Table 1a, Station dc supply, 18 calendar month, the verify item “Float voltage of battery charger” is not listed in Table 1b. Is this requirement independent of the level of monitoring and always required? If so, should it be added in to Table 1b and 1c, Station dc supply, 18 calendar months above the “Inspect:” section? 2)The 6 year interval maintenance activity for NiCad batteries in Table 1a and Table 1b should read “station battery” rather than “substation battery”. 3)It is recommended to simplify the Station dc supply sections in each of the three maintenance tables by relocating the common items that do not change dependent upon the level of monitoring. Specifically, the following rows of each of the three tables have identical maintenance requirements that are independent of the level of monitoring. The tables would be significantly simplified if these “monitor level independent” requirements are moved outside of the table: a.Station dc supply; 18 calendar months; Inspect: “ b.Station dc supply (that has a s a component Valve Regulated Lead Acid batteries) c.Station dc supply (that has as a component Vented Lead Acid batteries) d.Station dc supply (that has as a component Nickel Cadmium batteries) e.Station dc supply (battery is not used) 4)Table 1a has 18 calendar month requirements for “Station dc supply (battery is not used)”. This category is missing from Table 1b – was this intentional? 5)Table 1a has 6 calendar year and 18 calendar month requirements for “Station dc supply (battery is not used)”. This category is missing from Table 1c – was this intentional? 6)Please clarify the meaning of “Battery terminal connection resistance”. Does this apply only to multi-terminal batteries? Is this referring to the cables external to the battery (to the charger and load panel)? 7)Table 1c contains a Type of Protection System Component not found in any of the other tables: “Station dc supply (any battery technology). Is this the same as “Station dc supply” found in Tables 1a and 1b? 8)The Level 3 Monitoring Attributes for “Station dc supply (any battery technology)” are identical to the Level 2 Monitoring Attributes for “Station dc supply”. This appears to be duplicative in description with two different “maximum maintenance intervals” and “maintenance activities” listed. The following (3) comments pertain to the Voltage and Current Sensing Input component type: 1)Why is “signals” bolded in the Table 1a row for this component type? 2)Are the Table 1a, 12 year maintenance activities for this component type a duplication of the Table 1a, Protective relay, 6 year maintenance activity for microprocessor relays (verify acceptable measurement of power system input values)? 3)Why is this component type highlighted in bold in Table 1c? The following (8) comments pertain to the Control and Trip Circuit component type: 1)Why are microprocessor relay initiated tripping schemes excluded from the 6 year complete functional testing? The auxiliary relay operations resulting from these initiating devices are just as likely to stick (mis-operate) as those initiated from electromechanical devices. 2)We propose simplifying Table 1a for this component type by grouping the two 6 year and the two 12 year interval maintenance lines into two rather than four table rows. The 6 year interval maintenance activities for the UFLS/UVLS systems could be addressed in the table row above using a parenthetical adder to the existing text = (for UFLS/UVLS systems, the verification does not require actual tripping of circuit breakers or interrupting devices). All of the other text in the UFLS/UVLS table row matches that found two rows above. The same parenthetical adder in the first 12 year interval row for this component type would eliminate the need for the (UFLS/UVLS Systems Only) row for 12 year intervals. 3)If the two rows are combined as suggested previously – this comment is irrelevant: The Table 1a 6 year interval activity for UFLS/UVLS Systems Only is missing the word “contacts” after auxiliary. 4)There appears to be no difference in the 6 year interval maintenance activities for this component type in Table 1a and Table 1b. Table 1b monitoring attributes include “Monitoring and alarming of continuity of trip circuits”, but the interval between electrically operating each breaker trip coil, auxiliary relay, and lockout relay remains at 6 years. What maintenance activity advantage do the Level 1b monitoring attributes provide? 5)The difference between the two DC Control Circuits in Table 1b (on page 14) is unclear. What is the difference between the “Control Circuitry (Trip Circuits)” and the “Control and trip circuitry”? We propose combing the multiple table rows for this component type into a single line item for this component type, as it takes a combination of the protective relay action, any auxiliary relay, and the circuit breaker to comprise a complete tripping system. 6)We have three questions on the monitoring attributes given for this component type on page 14: a) Does the attribute beginning “Monitoring of Protection …” indicate a requirement to monitor every input, every output, and every connection of every Protection System Component involved in each tripping scheme? b) Does the attribute beginning “Connection paths…” related to monitoring of communication paths? c) Does the attribute beginning “Monitoring of the continuity…” require the presence of coil monitoring of any auxiliary relay whose contact is encountered when tracing a tripping path from a protective relay to a breaker? 7)Are the Table 1c attributes for this component type different from the monitoring described in Table 1b beginning “Connection paths…”? 8)Are there no requirements to operate any relays functionally for “Protection System control and trip circuitry” in Table 1c? The devices need to be exercised some or they will not be reliable. The following (1) comment pertains to the Associated communications system component type: 1)The Table 1b monitoring attribute for this component type (communications channel monitor and alarm) clearly should (and does) eliminate the Table 1a, 3 month interval activity (verifying the communication system is functional). The common maintenance activities found in Table 1a (6 year) and Table 1b (12 year) should be same interval – either 6 or 12.
Yes
 
Yes
 
 
Yes
 
Yes
 
General FAQ 1)Attached is an elementary drawing showing a typical transmission line relay protection scheme utilizing SEL-351S and SEL-321 microprocessor relays. Does this qualify as partially monitored control circuitry? See pdf file Control Elementary_1-07-13 & Control Elementary_2-07-13in email documentation sent to Al McMeekin. •If not, and this is an unmonitored circuit, what would be the appropriate maintenance interval (6 years or 12 years) for the Control and Trip Circuits from page 9 of PRC-005-2? The description of the two choices is ambiguous See pdf file PRC-005-2_clean_2 010June8.pdf in email documentation sent to Al McMeekin. •If not, what would it take to make this circuit partially monitored (including inputs)? 2) Table 1a, page 9, row 2 (Voltage and Current Sensing Inputs) Question – Does this mean secondary quantities from CT’s and VT’s only? If so, please consider changing the wording from “Voltage and Current Sensing Inputs” to “CT and VT secondary quantities”. 3) Table 1a, page 9, row 3 (Control and trip circuits with EM contacts) Question - Does "electromechanical trip or auxiliary contacts" mean EM protective relay outputs and EM tripping/lockout tripping contacts only? Or does it also include any part of the trip circuitry such as cutout switch contacts and breaker trip coils plus associated aux. breaker contacts. For example, the schematic with a microprocessor relay described in the first bulleted item could be considered an unmonitored EM control circuitry (6 year interval). Is this because of the mechanical breaker aux contacts, breaker maintenance switch, and FT-1 test switch? If so, how could any control circuitry fall in the solid state trip contacts category (12 year interval)? 4) Table 1a, page 9, rows 3, 4, 5, 6 – Please consider rewording these to make it clear where control schemes with MP relays that do have trip coil / circuit monitors but don’t meet the Partially Monitored requirements fit. (Does this type scheme fit in the 6 year trip test category or the 12 year category?) 5) Table 1a, page 12, row 1 – The maintenance requirements are not the latest wording used for all other Protective Relays. Please consider changing for consistency. 6) Table 1b, page 13, row 1 (Protective Relays) - Line three of the maintenance activities requires us to check inputs and outputs. The last maintenance item is to verify correct operation of output actions that are used for tripping. Question - How is this different than the line three maintenance requirements to check inputs and “outputs”? 7) Table 1b, page 14, rows 1 and 2 – Consider combining these into one row. The maintenance intervals and maintenance activities are these same. Please specify what is required for UFLS and UVLS control schemes). 8) Table 1b, page 14, rows 1 – The first sentence is very general for a monitoring attribute. (“Monitoring of Protection System component inputs, outputs, and connections with reporting of monitoring alarms to a location where action can be taken.”) Consider deleting this row or make it more specific. 9) Table 1b, page 14, row 2 [Control Circuitry (Trip Circuits) (except for UFLS/UVLS)] Question: Should there be a 12 year functional trip test requirement for this partially monitored control circuitry? Should this be added to Table 1b? 10) Table 1b, page 14, row 1 [Control Circuitry (Trip Circuits) (except for UFLS/UVLS)] - It states Monitoring of Protection System component inputs, outputs, and connections … Question – what does “inputs” mean? There are Protection System components such as protective relays, control circuitry, station dc supply, associated communications systems, etc. Does this mean we must monitor inputs to any or all of these Protection System components? How would this be accomplished? 11) Table 1c, page 18, row 4 – Should there still be a requirement to trip breakers by all trip coils every 6 years? Supplementary Reference Document 12) Question on Figure 1, page 27 - Box 1 denoting Protection Relays includes Aux devices, Test or Blocking Switches. The Aux devices, Test or Blocking Switches should be part of Box 3 (Control Circuitry). Please correct or note accordingly. FAQ Document 13) On Page 30, please add an Example with Partially Monitored (Level 2) Control Circuit. 14) On the Control Circuit Decision Tree on page 36, the flow chart does not match the current Table 1 requirements. They match the previous version which is described in the first question of this document. We still propose leaving the flow chart on page 36 as is and change Table 1 to match the original requirements. 15) Please consider adding a diagram /elementary drawing of a Partially Monitored Control Circuit showing the trip output contacts, inputs, etc that must be monitored to meet the Monitoring Attributes / Requirements. A diagram showing an Unmonitored control scheme and what it would take to make it Partially Monitored would be helpful too. Additional General FAQ 16)PRC-005-2, R1 requires the Functional Entity to establish a Protection System Maintenance Program (PSMP). It is not clear if this standard establishes a specified frequency for reviewing and updating the PSMP itself or the PSMP criteria outlined in subparts 1.1 through 1.4. By comparison, EOP-005-1 System Restoration Plans, requires the Functional Entity to (a) have a restoration plan and (b) to review and update the restoration plan annually (see EOP-005-1, R1 and R2). This approach to a comprehensive and periodic review considers the PSMP as a whole and is independent of the specific maintenance methods (time-based, condition-based, or performance-based) and maintenance intervals for those respective methods. It is noted however that PRC-005 Attachment A mentions annual updates to the list of Protection System component. According to the Attachment’s subtitle, Criteria for a Performance-Based Protection System Maintenance Program, this annual update seems limited to performance-based maintenance and not inclusive of other maintenance methods. The recommendation is to evaluate the need for a periodic review of the PSMP as a whole. 17)R1, Criteria 1.1, and companion VSL. This Criterion requires the identification of all Protection System components. The VSL for R1 uses a percent-based approach to parse out different quantities of components across the four VSL categories. This implies that a Functional Entity must have the ability to put a numerical quantity on its various components and should be able to demonstrate within certain tolerances that its components are included (or counted). If the number of components within scope amount to hundreds or thousands of individual items, the PSMT SDT should consider the Functional Entities’ ability to track and quantify the items for a compliance demonstration. If an entity is not able to reasonably quantify which components are in scope, demonstrating compliance on a percent-basis may prove difficult or impossible. Further review may indicate the need to reformat the VSL. Similar concerns are noted in other VSLs (R2, R3, and R4) and in Attachment A where percentage-of-components are mentioned. 18)R4 essentially requires the Functional Entity to implement its PSMP. R4 takes care to highlight the specific task of “identification of the resolution of all maintenance correctable issues.” It is noted that other “identification tasks” are included as criterion for the PSMP in R1. If these tasks are all appropriately categorized as identification-type tasks, it may be more efficient to restructure the standard by incorporating this task into R1 with the other criteria. R4 could remain as a basic implementation requirement with more detail provided in subparts 4.1, 4.2, and 4.3. 19)Footnote No. 2 describes maintenance correctable issues and could be interpreted as a potential new term for inclusion in NERC’s Glossary of Terms. The PSMT SDT should conduct further review of this terminology as a potential new Glossary term. 20)At R4, subpart 4.3, insert “design” such that it reads as follows: “Ensure that the components are within acceptable design parameters at the…” Also, this subpart duplicates Footnote No. 3 which describes “maintenance correctable issues” and was established in the main requirement R4 at Footnote No. 2.
Group
SERC Protection and Control Sub-committee (PCS)
Joe Spencer - SERC staff and Phil Winston - PCS co-chair
SERC Relaibility Corp.
No
Clarifications need to be made on testing requirements on trip contacts relative to microprocessor vs. EM relays. There appears to be an inconsistency in the use of “check” vs. “verify” in the tables. Also, Table 1B, in the second to last row, should be referring to UFLS rather than SPS. Also, note that M2 incorrectly excludes distribution provider. In battery maintenance table, we suggest that “cell/unit” be changed to “cell or unit.”
The SERC PCS expresses no opinion on this question.
Yes
The SERC PCS expresses no comments on this question.
No
In R1, a “Failure to specify whether a component is being addressed by time-based, condition-based, or performance-based maintenance” by itself is a documentation issue and not an equipment maintenance issue. Suggest this warrants only a lower VSL, especially when one of the required components can only be time based.
The SERC PCS expresses no opinion on this question.
The SERC PCS expresses no opinion on this question.
Descriptors in the "type of the protection system component" column need to be consistent between 1A, 1B and 1C. Also, in the tables, please clarify “complete functional trip test” for UVLS and UVLS trip tests since the breaker is not being tripped. Facilities Section 4.2.1 “or designed to provide protection for the BES” needs to be clarified so that it incorporates the latest Project 2009-17 interpretation. The industry has deliberated and reached a conclusion that provides a meaningful and appropriate border for the transmission Protection System; this needs to be acknowledged in PRC-005-2 and carried forward. We commend the SDT for developing such a clear and well documented second draft. The SDT considered and adopted many industry comments on the first draft. It generally provides a well reasoned and balanced view of Protection System Maintenance, and good justification for its maximum intervals. The SERC Protection & Control Subcommittee generally agrees that this second draft will be beneficial to BES reliability.
Individual
John Canavan
NorthWestern Corporation
No
Table 1a - Rows 3 & 4 (control and trip circuits) - add language in the Maintenance Activities - "except that verification does not require actual tripping of circuit breakers or interrupting devices"
 
 
 
 
 
 
Individual
Dan Roethemeyer
Dynegy Inc.
No
We agree with all proposed intervals in Tables 1a, 1b, and 1c except the 3 calender month interval for Associated Communication Systems in Table 1a. We suggest using a 1 year interval because all other elements of the Protection System are being verified a minimum of every 3 years. Therefore, we believe annual verification of Associated Communication Systems is sufficient.
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
For protection system component verification, flexibility is needed subsequent to a system event to allow the analysis of a protection system operation to be utilized as a protection system component verification. We believe this flexibility is needed and should be incorporated in Requirement R4.
Individual
Robert Ganley
Long Island Power Authority
No
In Table 1c it is required to report the detected maintenance correctable issues within 1 hour or less to a location where action can be taken to initiate resolution of that issue. Even for a fully monitored protection system component it can be difficult to report the action in 1 hour. LIPA recommends a 24 hour period for both Level 2 and Level 3 reporting of maintenance correctable issues. The time identified is report time and not response time to correct issue. LIPA seeks clarification on “to a location where action can be taken”. Some examples in the FAQ will help in this clarification. What type of documentation is required to show compliance that maintenance correctable issues have been reported? What is the basis of the various Maximum Maintenance Intervals tabulated in Table 1a-Time based maintenance?
Yes
 
No
Two most recent performances of each distinct maintenance activity for the Protection System components will require data retention for an extended period of time. For example, in certain cases, battery maintenance is on a 12 year cycle which suggests that records need to be retained for 24 years. LIPA suggests retaining data for the most recent maintenance activity. LIPA seeks clarification on “on-site audit” – does it include audits by any of the following - NPCC/NERC/FERC. Also, several small entities do not have on-site audits and participate in off-site audits. Hence, LIPA suggests deleting “on-site” from the requirement. In addition further clarification is required to the Data Retention section to coordinate with the statement in FAQ (Section IV.d p. 22 redline).
No
R4 under Severe VSL mentions – Entity has failed to initiate resolution of maintenance-correctable issues. What proofs will satisfy the requirement that the entity has initiated the resolution. R1 under Severe VSL – LIPA suggests moving the first criteria “The entity’s PSMP failed to address one or more of the type of components included in the definition of “Protection System” under High VSL since this criteria cannot have the same VSL level as “Entity has not established a PSMP”.
No
There is no guidance on how to calculate the total number of components and thus, the percentages under different severity levels. FAQ provides some insight into how an entity can count components however; an example in the reference document will provide clarity. Page 7 of the redline version of Supplemental Reference – bullet 1 under Maintenance Services, paragraph 2, it says “ If specific protection scheme components have demonstrated correct performance within specifications, the maintenance test time clock is reset for those components. LIPA believes that resetting the time clock will make tracking difficult (unless entities have a sophisticated automated tool for tracking). Another option where an entity can take credit for a correct performance within specifications at the time of the maintenance cycle should be included.
Yes
 
Table 1a under Maintenance Activities for Control and trip circuits with unmonitored solid-state trip or auxiliary contacts (UFLS/UVLS Systems Only) states: Perform a complete functional trip test that includes all sections of the Protection System control and trip circuit, including all solid-state trip and auxiliary contacts (e.g. paths with no moving parts), devices, and connections essential to proper functioning of the Protection System., except that verification does not require actual tripping of circuit breakers or interrupting devices. The word complete may be removed as it requires actually tripping the breakers. The sentence that tripping of the circuit breakers is not required contradicts with the word complete. More specifics are required to spell out the adequate testing e.g. up to the lockout with the trip paths isolated etc. Table 1a under Maintenance Activities for Station dc Supply (used only for UVLS or UFLS) states: Verify proper voltage of the dc supply. Is this requirement applicable to the distribution substations only? Table 1a under Maintenance Activities for Station dc supply (battery is not used) – states Verify that the dc supply can perform as designed when the ac power from the grid is not present. - Please clarify this requirement. Table 1a for Associated communications systems - specify the group for the applicability of this requirement. BPS,BES,UFLS etc. Table 1a under Maintenance Activities for Associated communications systems states – Verify that the performance of the channel meets performance criteria, such as via measurement of signal level, reflected power, or data error rate. Why is this required? The requirement "Verify proper functioning of communications equipment inputs and outputs that are essential to proper functioning of the Protection System. Verify the signals to/from the associated protective relays seems sufficient to ensure reliability. Table 1a under Maintenance Activities for Relay sensing for Centralized UFLS OR UVLS systems UVLS and UFLS relays that comprise a protection scheme distributed over the power system states: Perform all of the Maintenance activities listed above as established for components of the UFLS or UVLS systems at the intervals established for those individual components. The output action may be breaker tripping, or other control action that must be verified, but may be verified in overlapping segments. A grouped output control action need be verified only once within the specified time interval, but all of the UFLS or UVLS components whose operation leads to that control action must each be verified. Clarify what is meant by overlapping segments? What is the specified interval? Is actual breaker tripping required?
Group
Pacific Northwest Small Public Power Utility Comment Group
Steve Alexanderson
Central Lincoln
No
We agree with most of the changes from the last draft. However, the phrase “Verify Battery cell-to-cell connection resistance” has entered the table where it did not exist before. On some types of stationary battery units, this internal connection is inaccessible. On other types the connections are accessible, but there is no way to repair them based on a bad reading. And bad cell-to-cell connections within units will be detected by the other required tests. This requirement will cause entities to scrap perfectly good batteries just so this test can be performed, with no corresponding increase in bulk electric system reliability while taking an unnecessary risk to personnel and the environment. And because buying battery units composed of multiple cells allows space saving designs, entities may be forced to buy smaller capacity batteries to fit existing spaces. This may end up having a negative effect on reliability. Suggest substituting “unit-to-unit” wherever “cell-to-cell” is used in the table now.
Yes
 
Yes
 
No
is possible that a component that failed to be individually identified per R1.1 was included by entity A’s maintenance plan. This documentation issue gets a higher VSL than entity B that identified a component without maintaining it. We suggest the R1 VSL be change to Low, since we believe lack of maintenance to be more severe than documentation issues.
Yes
 
Yes
 
The level 2 table regarding Protection Station dc supply states that level 1 maintenance activities are to be used, but then goes on to give a list of Maintenance Activities that don’t match those in level 1. Which activities shall we use? Same situation for Station DC Supply (battery is not used) where the 18 month interval is missing. IEEE battery maintenance standards call for quarterly inspections. These are targets, though, not maximums. An entity wishing to avoid non-compliance for an interval that might extend past three calendar months due to storms and outages must set a target interval of two months thereby increasing the number of inspections each year by half again. This is unnecessarily frequent. We suggest changing the maximum interval for battery inspections to 4 calendar months. For consistency, we also suggest that all intervals expressed as 3 calendar months be changed to 4 calendar months. We are concerned over R1.1, where all components must be identified, without a definition for the word component or the granularity specified. While the FAQ gives a definition, and allows for entity latitude in determining the granularity, the FAQ is not part of the standard. We believe this will allow REs to claim non-compliance for every three inch long terminal jumper wire not identified in a trip circuit path. We suggest that the FAQ definitions be included within the standard.
Group
PNGC Power
Margaret Ryan
PNGC Power
No
We agree with most of the changes from the last draft. However, the phrase “Verify Battery cell-to-cell connection resistance” has entered the table where it did not exist before. On some types of stationary battery units, this internal connection is inaccessible. On other types the connections are accessible, but there is no way to repair them based on a bad reading. And bad cell-to-cell connections within units will be detected by the other required tests. This requirement will cause entities to scrap perfectly good batteries just so this test can be performed, with no corresponding increase in bulk electric system reliability while taking an unnecessary risk to personnel and the environment. And because buying battery units composed of multiple cells allows space saving designs, entities may be forced to buy smaller capacity batteries to fit existing spaces. This may end up having a negative effect on reliability. Suggest substituting “unit-to-unit” wherever “cell-to-cell” is used in the table now.
Yes
 
Yes
 
No
It is possible that a component that failed to be individually identified per R1.1 was included by entity A’s maintenance plan. This documentation issue gets a higher VSL than entity B that identified a component without maintaining it. We suggest the R1 VSL be change to Low, since we believe lack of maintenance to be more severe than documentation issues.
Yes
 
Yes
 
The level 2 table regarding Protection Station dc supply states that level 1 maintenance activities are to be used, but then goes on to give a list of Maintenance Activities that don’t match those in level 1. Which activities shall we use? Same situation for Station DC Supply (battery is not used) where the 18 month interval is missing.
Individual
Terry Harbour
MidAmerican Energy Company
No
In the tables trip circuit has been replaced by “control and trip circuit”. From the context of the standard and the reference and frequently asked question documents it is clear that the requirement is to test the trip circuit only. Adding the word “control’ introduces ambiguity and the potential to imply the closing circuit of the interrupting device also requires testing under the standard. The word “control” should be removed. On this same subject the nomenclature in Table 1b for type of protection system component is not consistent with Table 1a. In Table 1b in the Level 2 Monitoring Attributes for Component column for Relay sensing for centralized UFLS or UVLS systems there is a reference to SPS. This reference should likely be to UFLS/UVLS. In Table 1a functional testing of associated communications systems is included with a maximum maintenance interval of 3 calendar months. Testing of this equipment at that frequency is not believed to be necessary. It is suggested that the interval be changed to 12 calendar months. For control and trip circuit maintenance the requirement includes “a complete functional trip test”. In order to accomplish this type of testing given current design of lock-out relay and interrupting device trip circuitry multiple breakers and line terminal outages would be required simultaneously. In addition complete functional testing has the potential to result in unintentional tripping of equipment that could cause equipment damage and customer outages. Segmentation of trip circuits by lifting wires has the potential for incorrect restoration following testing. This type of testing has the potential to degrade system reliability as multiple entities schedule this work. An alternate to complete functional testing that does not potentially degrade system reliability should be substituted.
Yes
 
No
Verification of compliance with the maximum time intervals for testing only needs to include retention of the documentation of the two most recent maintenance activities. The phrase “or to the previous on-site audit (whichever is longer)” should be deleted.
No
The lower VSL specification for R4 should allow for a small level of incomplete testing. Suggest changing “5% or less” to “from 1% to 5%”.
Yes
 
Yes
 
From the compliance registry criteria for generator owner/operator and the language in 4.2.5.3 it is implied that the intent is that protection systems for individual generators less than 20 MVA would not be covered by PRC-005. To make this clear in the PRC-005-2 standard, the following footnote to section 4.2.5.3 is recommended: Protection systems for individual generating units rated at less than 20 MVA in aggregated generation facilities are not included within the scope of this standard. The Request for Interpretation of a Reliability Standard submitted March 25, 2009 indicates that a protection system is only subject to the NERC standards if the protection system interrupts the BES and is in place to protect the BES. The following changes are recommended to clarify this in the standard: A.3. Purpose: To ensure all transmission and generation Protection Systems protecting and affecting the reliability of the Bulk Electric System (BES) are maintained. A.4.2.1. Protection Systems applied on, or and designed to provide protection for the BES. B.R1. Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a PSMP for its Protection Systems that use measurements of voltage, current, frequency and/or phase angle to determine anomalies and to trip a portion of the BES and that are applied on, or and are designed to provide…….. FERC Order 693 includes the directive that “testing of a protection system must be carried out within a maximum allowable interval that is appropriate to the type of the protection system and its impact on the reliability of the Bulk-Power System”. If unanticipated conditions (e.g. force majeure) of the bulk-power system do not allow outages to complete protection system maintenance as required by the standard without compromising the reliability of the system delay of the particular maintenance activity should be allowed. This provision should be included in the standard in R4.
Individual
Jonathan Appelbaum
The United Illuminating Company
Yes
In general yes. There are concerns with verifying cell-to-cell resistance in Batteries. On some battery sets this is not possible to do.
No
: The VRF for R1 should be Low. It is administrative to create an inventory list. If R1 failed to be executed but the other requirements wee executed fully then the BES would be properly secured. Compare this against the scenario of performing R1 but failing to perform the other tasks; in which case the BES is at risk. UI recognizes that the SDT considers the inventory as the foundation of the PSMP but it is not the element of the PSMP that provides for the level of reliability sought. R1 should be VERF Low and R2 thru R4 VRF is Medium. UI agrees with the Time Horizon.
Yes
 
Yes
 
No
Include a detailed example of an Inventory list. Allow for different means of maintaining the lists electornically, that is, as spreadsheets, or databases.
No
What actions are taken if the owner can not perform a specific activity elaborated on the tables due to the design of the equipment? Is the owner in non-compliance? Must the owner only accept equipment solutions that allow the maintenance activities elaborated in the standard to be performed?
 
Individual
Lauri Dayton
Grant County PUD
 
 
 
 
 
 
PRC005-02 Comment We offer some comment for your consideration for incorporation into the Standard PRC-005-02 (draft) as presented in the May 27th 2010 PRC 005-02 “Standard Development Roadmap.” RE: Comment on the 2nd Draft of the Standard for Protection System Maintenance and Testing” 1) The term “The Protection System Maintenance Program” (Page 2) appears to be centered on the concept of maintaining specific components as stand alone objects, and therefore infers that the resultant documentation be organized in a similar fashion. Neither is optimal from a practical or a functional perspective. Many rational work practices combine components (example, meggering from the relay input test switch through the cables and the CTs) in the interest of minimizing circuit intrusion and human error. For this reason, such maintenance practices are superior from a reliability standpoint. The t emphasis on “components” in the current draft is, at best, tangential to NERC’s stated goal and purpose of PRC-005 to improve reliability. How would we fix this? We would insert the phrase “or Element”—as defined in NERC’s Glossary of Terms to include “one or more components / devices with terminals that measures voltage, current, frequency and/or phase angle” to determine anomalies and to trip a portion of the BES” immediately after any occurrence of the word “component” in each of the Requirements or in a Definition paragraph, intending it to be applied globally to R-1 through R4. This would foster the validity of maintenance activities being applied to aggregations of components — “Elements”—such as would occur during Verification of DC control circuitry or through the employment of fault data analysis. 2) Protection System Maintenance Program. The categorization of maintenance into 7 maintenance activities is welcomed as advancing practices which foster BES reliability. Likewise we find the clarifications denoted by superscripts 1 and 2 helpful. However….under C: MEASURES: M1, the last sentence of the paragraph provides: “For each protection system component, the documentation shall include the type of maintenance program applied (time based, etc), maintenance activities (1 or more of the 7 identified) and maintenance intervals…..” This measure goes beyond the requirements of the standard and should be revised consistent with the deletion of the previous R.1.1 as shown in track changes under the version 2 draft which had included the identification of the maintenance activity associated with each component. COMMENT: It should be apparent in reviewing the evidence that one or more of the 7 listed activity categories are represented. The proscription to explicitly call out these categories is thus redundant---the requirement being that at least one has to be identifiable in the program—and will cause unnecessary complications to the Entity and interpretation issues in the Compliance monitoring effort. We recommend that the words “maintenance activities” be removed from the last sentence in the paragraph pertaining to C: MEASURES: M1. We also believe it is unnecessary to restate the definition of “Protection System” in the Measure. 3) A fundamental incompatibility exists between NERC’s proposition of “maximum maintenance (time based) interval” and the typical CMMS PM generation algorithm. SPCTF members and regional compliance engineers have verbally represented that the “maximum maintenance interval” is a precise term “not to exceed—even by one day---“ maximum, otherwise generating a fine-able Violation and that fixed intervals plus or minus a certain additional period of time to account for other operational exigencies are no longer going to be permitted. There is always an interval between the time a CMMS PM is issued and its completion. The time interval between the issue date and the completion date is normally a period of time to allow maintenance staff to schedule their work in an orderly fashion. The maximum time based interval is fixed by the time period specified for issuance of the planned maintenance (PM) work order (e.g. every 3 years) and the defined period of time to complete the work (usually described as a percentage of the PM interval e.g. 25%). So predicating a PM issue date based on the last issue date plus a percentage of the interval time to complete the work is not inconsistent with a fixed time interval. Under the proposed tables, however, there is no accommodation for this predominate maintenance practice. Even if maintenance intervals were shortened to ensure that the required completion date as defined by program intervals does not exceed the NERC maximum interval as described in the tables, this will not be sufficient because auditors may conclude that the tables permit the use of only a single defined interval and not permit an additional defined period of time to schedule and complete the work. Remember, it is immaterial whether the Entity’s interval is more stringent than the NERC maximum, a violation may occur if the maintenance is not performed within the Entity’s maintenance interval, even if it is shorter than the NERC maximum. A precise maximum interval requires constant managerial intervention on the part of the Entity to ensure that operational exigencies do not cause violations on a component-by component (or element) basis. The shortened interval would tend to destroy the sense of rhythm and pattern which should be manifest in a time based program. Further, after one or more iterations, seasonal restrictions on outages begin to impinge requiring adjustments to be made to the Maintenance Program document to adjust the interval or maintenance activity. At best, it results in a clumsy way of doing business and requiring significantly more oversight into keeping the maintenance program document updated for presentation to auditors rather than focusing on prudent maintenance activities as desired by FERC Order 693. Auditing is not any more difficult if the Maintenance Program also specifies that a percentage of a fixed target / time interval is allowed to schedule and complete the work—as meeting the interval requirements of a time based maintenance program. This method allows for a fixed time for issuance of the work order and maintenance personnel some flexibility to schedule and complete their work within a defined period of time. We recommend to vote against adoption until some more workable solution is identified and disseminated, satisfying both the Compliance Authority and the affected Entities. Specifically, we recommend that the drafting team adopt “target” intervals with a +/- range of acceptability, based on percentage or a fixed time per interval, which can be global for the Program or specific to the elements or components in question. The target intervals must be stated in the PSMP, the range of acceptability easily calculable and enforceable, and within the maximum intervals to be identified in the tables 1a, b, and c, satisfying compliance issues. This also allows the Entities to rationally plan their maintenance using existing CMMS technologies. 4) Within the Violation Security levels, we are aware of no activity by NERC to differentiate the relative criticalitiy of components or Elements of the BES system. For example, protection system components or Elements in a regional switchyard may present a larger potential for disruption of the BES in the event of a mis-operation than does one associated with one generator among fifteen others and which is more electrically remote from and of less consequence to the BES. Unless and until this issue is addressed, both the PRC-005 maintenance and documentation will be less effective and more expensive than it could be. 5) PRC-005-02’s proposed effective date is “See Implementation Plan.” This is not adequate to provide regulated entities with appropriate notice of the Effective Date of PRC-005-2 standard. ” Additionally, NERC has not posted the “Implementation Plan” for comment in the same manner as the proposed standard and thus we are not able to comment on the schedule provided in the Plan. We understand that the retention and documentation cycles go back three years and that a regulated entity, depending on the effective date of this standard and the entity’s audit cycle, will be audited to both PRC-005-1 and PRC-005-2 during the same audit period. Some further discussion should be given to allowing comment on the Implementation Plan because of the potential overlapping requirements during a single audit cycle.
Individual
Mark Fletcher
Nebraska Public Power District
No
It would be very helpful in Table 1a, 1b, and 1c to reference the FAQ or Supplemental Reference by page number and section number for the corresponding Maintenance Actiivity statements. Table 1a, Control and Trip Circuits with electromechanical trip or auxiliary contact – how is the control and trip circuit functional trip test performed without affecting the BES or without tripping more than just the breaker (trip coil)? What is the basis for an actual trip of the breaker that will affect the BES. Functional trip testing will require extensive analysis and could involve an extensive testing evolution to ensure the correct circuit is tested without unexpected trip of other components, particularly for generator protection systems. The complexity of the system and the test would be conducive to an erro that resulted in excessive tripping, thus affecting the reliability of the BES. It would seem that the potential for an adverse affect from this test would be greater than the benefit gained of testing the circuit. In addition, scheduling outages to perform the functional trip testing in conjunction with other outages required to perform maintenance and other construction activities will be difficult due to the large number of outage requiremetns for the fucntional testing. This will challenge the BES more often and thus reduce reliability. Table 1a, Control and Trip circuits with electromechanical trip or auxiliary contacts - What is the differentiation between control and trip circuits? The FAQ appears to use the term interchangeably. • Table 1a, Associated communication systems - What is the basis for checking that the associated communication equipment is functioning every 3 calendar months for unmonitored components?. NPPDs experience indicates that a check every 6 months is sufficient.
Yes
Please provide an example of how the compliane percentage will be calculated for the implementation plan.
Yes
Additional guidance on what is accepatable evidence is always good.
Yes
 
Yes
Is this document considered part of the standard and may be referenced during audit and self-certification as an authentic source of informaiton?
No
FAQ 2.G, page 24 – NPPD believes system reliablity will be decresed if an entity is considered non-compliant for exceeding a PSMP stated interval that is within the PRC-005-2 Maximum Maintenance Interval. Considering an entity non-compliant for such a situation will encourage establishment of intervals that only meet the minimum standard. There should be one standard interval that all entities must be monitored against. If an entity wants to perform maintenance more frequently, it should not be subject to non-compliance if it misses its target but meets the Maximum Maintenance Interval in the standard. There are definitions at the beginning of the FAQ that should be contained in the NERC definitions and not in an FAQ. Placing these in an approved definition will help avoid interpretation issues that would arise during future audits.
4.2.5.1 (And elsewhere in the standard) Please define auxiliary tripping relays. 4.2.5.5 Do station “system connected” service transformers that do not supply house load for the generating unit, other than during start up or emergency conditions, fall under this clause? If so, can these transformers be eliminated if the house load can be back-fed from “generator connected” service transformer switchgear? What if there are redundant “system connected” feeds? R1 1.4 Clarification requested. This wording would suggest all battery activities fall under Table 1.a. exclusively. R4 4.3 Does initiation of activities require documentation, or is inclusion of “initiation” in the testing procedure sufficient evidence? Tables 1b &1c: Suggestion: If at all possible, combine and simplify. The number of sub clauses and nuances that are being described in these sections (with little change to interval or procedures for that matter) is overwhelming. These two tables are setting RE’s and System Owners up for making errors. Implementation and auditability should be the focus of this standard, SIMPLIFY. • SPS – Does the output signal need to be verified, or does the actual expected action need to be verified. Actual expected action would affect electrical generation production for NPPD’s SPS.
Group
Tennessee Valley Authority
Dave Davidson
Transmission Operations and Maintenance (TOM) Support Group
No
The requirement to measure internal ohmic values of the station dc supply batteries every 18 months is excessive. The interval should be 36 months. Our experience from performing our routine maintenance program including cell impedance testing at 3-year intervals has been that the program is fully adequate in monitoring bank condition.
Yes
 
 
No
The Violation Severity Level Table listing for Requirement R4 lists the following under “Severe VSL”. “Entity has failed to initiate resolution of maintenance-correctable issues” The threshold for a Severe Violation in this case is too broad and too subjective. The threshold needs to be clearly defined with low, medium, and high criteria.
No
There needs to be a defined method of deferral when equipment can’t be gotten out of service until a scheduled outage. Give some examples of what “inputs and outputs that are essential to proper functioning of the Protection System” are. Define what a “Control and Trip Circuit” is. Is there one per relay? Do I have to have a list of them in my work management system?
No
If a relay is tested during a generator outage, what date is allowed to be used for compliance - actual test date or date equipment was returned to service? These are usually only a few weeks apart, but may be as much as three months different.
 
Individual
Brian Evans-Mongeon
Utility Services
 
 
 
 
 
 
With regard to DPs who own transmission Protection Systems, the standard is still very unclear on when a DP owns a transmission Protection System. Many DPs own equipment that is included within the definition of a Protection System; however, ownership of such equipment does not necessarily translate directly into a transmission Protection System under the compliance obligations of this standard. DPs need to know if this standard applies to them and right now, there is no certain way of determining that from within this language or previous versions of this standard. Additionally, the NPCC Regional Standards Committee withdrew a SAR on this very subject as we informed the question would be addressed in this proposal.
Group
Corporate Compliance
Silvia Parada Mitchell
NextEra Energy, Inc.
No
Battery visuals should be changed from 3 months to 6 months. Electrolyte levels of today’s lead-calcium batteries are relatively stable for a 6 month period compared to lead-antimony batteries used in the past.
 
 
 
 
 
 
Individual
Charles J.Jensen
JEA
No
1. R1.1 What is a Protection System component? Could the SDT provide a better understanding of what is meant by component? R4: A “Failure to specify whether a component is being addressed by time-based, condition-based, or performance-based maintenance” by itself is a documentation issue and not an equipment maintenance issue. Suggest this warrants only a lower VSL, especially when one of the required components can only be time based. 2. R4: Suggest a stepped VSL for “Entity has failed to initiate resolution of maintenance-correctable issues”. While we understand the importance of addressing a correctable issue, it seems like there should be some allowance for an isolated unintentional failure to address a correctable issue.
No
2. What role with the Supplementary Reference and FAQ play with reference to the proposed standard? We have a concern that the standard will stand-alone and not include the interpretations, examples and expalnations that are needed to properly apply these values in a compliance envoironment. There needs to be a method to include the FAQ and Supplementary Reference. The method will also need to allow for future modifications as the standard is revised, etc.
No
Data retention becomes a complex issue for maintenance intervals of 12 years where the last two test intervals are required to be kept, i.e. 24 years. It would seem much more reasonable to set a limt of two test intervals or the last regional audit, not having to keep some 24 years of documentation with maintenance systems changing and archival records somewhat problematic to keep.
No
We could find no rational provided for the % associated with each VSL, or component rationale used to determine the proposed values listed. Is this included in some documentation that is available but not included as part of this review?
No
The Supplementary Reference document is critical in our current compliance environment to be approved as part of ths standard and any standard modifications need to be kept in synchronization with the FAQ and the Supplementary Reference.
No
Yes the FAQ is also a very immportant document to be approved along with the standard. There must be a way to have the standard and the FAQ go hand-in-hand or the standard must be revised to include much of the FAQ.
The current interpretation by the SDT of paritally monitored is set at a higher bar than most uttilities use in the their current designs today. We all wish to take advantage of the microprocessor relays and their renowned and improved montoring capability. If TC1 is monitored by primary relay A and TC2 is monitored by primary relay B, and these relays in turn monitor their DC supplies, the vast majority of the system is monitored - (partially monitored), including all the control cable out to the remote breakers and their trip coils. To add to this some additional contacts within the scheme, located very near the primary relays, is extending the partially monitored bar to a higher level than most designs incorporate today. If you know that 98% of the DC control system is monitored - isn't that paritally monitored? Please consider changes to the SDT's current view of a paritally monitored protection systems.
Group
Arizona Public Service Company
Jana Van Ness, Director Regulatory Compliance
Arizona Public Service Company
No
The associated maintenance activities are too prescriptive. The activities needed to ensure the reliable service of the relay or device should be left up to the discretion of the utility.
Yes
 
No
The change to the Protection System definition and establishing a PSMP with prescriptive maintenance activities relative to the voltage and current sensing devices has created a situation where data from original or prior verification not being available or not at the interval to meet the data retention requirement. Although, methods of determining the integrity of the voltage and current inputs into the relays were used to ensure reliability of the devices meets the utilities requirements, they may not meet the interval requirement and would then be considered a violation due to changes in the standard. Recommend a single exemption of the two recent most recent performances of maintenance activities to the most recent performance of maintenance activity in the first maintenance interval for this component due to the long maintenance interval, the changes in the standard definitions and the prescriptive maintenance activities.
Yes
 
Yes
 
Yes
 
The generator Facilities subsections 4.2.5.1 through 5 are too prescriptive and inconsistent with sections 4.2.1 through 4. Recommend this section be limited to description of the function as in the preceding sections. Clarification is needed on how the “Note 1” in Table 1a, which appears to be used in to define a calibration failure would be used in Time Based Maintenance. In PRC-005-2 Attachment A: Criteria for a Performance-Based Protection System Maintenance Program, a calibration failure would be considered an event to be used in determining the effectiveness of Performance Based Maintenance. It is unclear in how it will be used in time based maintenance.
Individual
Scott Berry
Indiana Municipal Power Agency
 
 
 
 
 
 
The proposed effective date working is confusing and maybe incorrect. It looks like the second part of the paragraph refers to the additional maintenance and testing required by requirement 2 of the current version of PRC-005-1. PRC-005-2 will be adding additional maintenance and testing. Since the current wording is confusing, we are not sure when we have to ensure the new testing is done on the protection equipment. When it comes to battery maintenance, the battery cell to cell connection resistance has to be verified. IMPA is not sure how the SDT wants this maintenace performed. Some battery banks are made up of individual battery cases with two posts at each end that contain two to four individual battery cells inside of each case. To actually tear down the individual cells in a case would be extremely hard and maybe impossible on the sealed cases without destroying the cases. It would be nice to describe how the SDT wants the connection resistance of battery cell to cell verified in the FAQ guide. In the same guide, the SDT might give insight on what is meant by verifing the state of charge of the individual battery cell/units (table 1A). It seems like measuring the voltage level of the individual battery would work for this verification, but addditional information of what the SDT wants for this verification would eliminate any doubt and help with being in compliant with this requirement.
Individual
Fred Shelby
MEAG Power
No
1. The descriptoins for the "type of protection system components" do not appear to be consistent between Tables, 1a, 1b and 1c. 2. The maximum maintenance interval for a lead-acid vented battery is listed at 6 calendar years for performing a capacity test.This type of test has been proven to reduce battery life and an interval of 10 to 12 years would be better. 3. The maximum maintenance interval for "Station DC supply" was set at 3 months. This is too short of a period and 6 months would be better. 4. The control and trip circuits associated with UVLS and UFLS do not require tripping of the breakers but all other protection systems require tripping of the breakers, this appears to be inconsistent? 5. Digital relays have electromagnetic output relays. Do they fall into the electromechanical trip or solid state trip? 6. Need for clarification: The standard indicates that only voltage and current signals need to be verified. Does this mean that voltage and current transformers do not need to be tested by applying a primary signal and verifying the secondary output?
Yes
 
Yes
 
Yes
It would be good to have the basis of the 5%, 10% and 15% defined. With time and experience these percentages may need to be changed.
No
Further clarification is needed. The information provided on verifying outputs of voltage and current sensing devices is confusing. In one part, it indicates that the intent is to verify that intended voltages and currents are getting to the relay apparently without regards to acccuracy. A pactical method of verifying the output of VTs and CTs is not identified and need to be identified.
No comment.
No comment.
Individual
James A. Ziebarth
Y-W Electric Association, Inc.
No
Many of the changes to the proposed standard are reasonable and improve the clarity of the standard and its requirements. However, Y-WEA concurs with Central Lincoln and FMPA on their comments regarding the testing of battery cell-to-cell connection resistance. Many types of stationary batteries are actually blocks of two or more cells that are internally connected. This requirement would necessitate either some sort of feasibility exception process (which, as shown by the TFE process with the CIP standards can be very difficult, cumbersome, and time-consuming to develop and administer) or replacement of the batteries in question, which would pose enormous burdens on small entities that must comply with this standard. The language in this requirement should be changed from “cell-to-cell” to “unit-to-unit” in order to avoid these issues.
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Y-WEA concurs with Central Lincoln regarding the timing of required battery tests. The IEEE standards referenced indicate target maintenance intervals. In order to remain reasonable, then, this compliance standard needs to allow some buffer between a targeted maintenance and inspection interval and a maximum enforceable maintenance and inspection interval. Central Lincoln’s suggestion of a four-month maximum window is reasonable and should be incorporated into the standard. Y-WEA is also concerned with R1.1’s language indicating that all components must be identified with no defined “floor” for the significance of a component to the Protection System. The SDT cannot possibly expect that a parts list containing every terminal block, wire and jumper, screw, and lug is going to be maintained with every single part having all the compliance data assigned to it, but without clearly stating this, that is exactly the degree of record-keeping that some overzealous auditor could attempt to hold the registered entity to. The FAQ is much clearer as to what is and is not a component and should be considered for the standard. Y-WEA also concurs with FMPA’s comments regarding the testing of batteries and DC control circuits associated with UFLS relaying. Many UFLS relays are installed on distribution equipment. Furthermore, many distribution equipment vendors are including UFLS functions in their distribution equipment. For example, many recloser controls incorporate a UFLS function in them. These controls and the reclosers they are attached to, however, are strictly distribution equipment. 16 USC 824o (a)(1) limits the definition of the Bulk-Power System to “not include facilities used in the local distribution of electric energy.” A distribution recloser and its control clearly fall into this exclusion. 16 USC 824o (i)(1) prohibits the ERO from developing standards that cover more than the Bulk-Power System. As such, the DC control circuitry and batteries associated with many UFLS relaying installations are precluded from regulation under NERC’s reliability standards and may not be included in this standard because they are distribution equipment and therefore not part of the Bulk-Power System. The proposed standard needs to be rewritten to allow for this exclusion and to allow for the testing of only the UFLS function of any distribution class controls or relays.
Individual
Armin Klusman
CenterPoint Energy
 
 
 
 
 
 
CenterPoint Energy believes the proposed Standard is overly prescriptive and too complex to be practically implemented. An entity making a good faith effort to comply will have to navigate through the complexities and nuances, as illustrated by the extensive set of documents the SDT has provided in an attempt to explain all the requirements and nuances. The need for an extensive “Supplementary Reference Document” and an extensive “Frequently Asked Questions Document”, in addition to 13 pages of tables and an attachment in the standard itself, illustrate that the proposal is too prescriptive and complex for most entities to practically implement. CenterPoint Energy is opposed to approving a standard that imposes unnecessary burden and reliability risk by imposing an overly prescriptive approach that in many cases would “fix” non-existent problems. To clarify this point, CenterPoint Energy is not asserting that maintenance problems do not exist. However, requiring all entities to modify their practices to conform to the inflexible approach embodied in this proposal, regardless of how existing practices are working, is not an appropriate solution. Among other things, requiring entities to modify practices that are working well to conform to the rigid requirements proposed herein carries the downside risk that the revised practices, made solely to comply with the rigid requirements, degrade reliability.
Individual
Kasia Mihalchuk
Manitoba Hydro
No
The monitoring attributes required to achieve level 2 monitoring of Station DC supply seem excessive. We are not aware of any other utilities doing automatic monitoring all 6 attributes required. In particular automatic monitoring of electrolyte level & battery terminal resistance does not seem practical. There is inconsistency between Table 1 and the FAQ. In the Group by Monitoring Level section of the FAQ it indicates that a battery with low voltage alarm would be considered to have level 2 monitoring. In Table 1C under the heading "Maximum Maintenance Interval" some of the entries are stated as being "Continuous". In the case of other maintenance activities the descriptor for Maintenance Interval indentifies the maximum period of time that may elapse before action must be taken. "Continuous" implies continuous action, however, in reality continuous monitoring enables no maintenance action to be taken until such time as trends indicate the need to do so. Therefore we recommend that where the maintenance interval be changed to read "Not Applicable".
No
Time horizons to change from present 6 months to 3 months maintenance time intervals within proposed implementation time period is not realistic.
Yes
No issues or concerns at present
Yes
There is no rational provided for the % associated with each VSL, or component rationale used to determine the proposed values listed.
Yes
 
Yes
 
Once the new Standard is approved, NERC must allow for a greater implementation stage and no further changes proposed for the foreseeable future. It does take a lot of resources for a Utility to make the required changes in maintenance frequency templates or type of maintenance required as per the proposed "Standard". Regarding the use of the term “Calendar” (i.e. end of calendar year) for maximum maintenance interval. Our utility uses end of fiscal year as our cutoff date for completing maintenance tasks for a given year. It would be considerable work for us to have to switch to end of calendar year with zero improvement in our overall reliability. We suggest it be left up to each utility to define their calendar yearly maintenance cycle when all tasks for that year must be completed.
Individual
Edward Davis
Entergy Services
No
1. Table 1a has a “Control and trip circuits with electromechanical trip or auxiliary contacts (except for microprocessor relays, UFLS or UVLS)” component type listed, and there is a “Control and trip circuits with electromechanical trip or auxiliary [editorial comment: add ‘contacts’] (UFLS/UVLS systems only)” component type listed. Suggest a “Control and trip circuits with electromechanical trip or auxiliary contacts” for a microprocessor relay application should be addressed since it seems to be missing. 2. The term “check” has replaced “verify” for some of the maintenance activities in this draft version. What is the difference between these two terms, and shouldn’t “check” be defined if it is to be included as a PSMP activity term? 3. Assuming the term “check” replaced “verify proper functioning” in order to allow for the completion of a maintenance activity within the required interval and yet account for a maintenance correctable issue being present, suggest the other remaining activities in the tables where the term “verify proper functioning” is used, also be replaced with “check”. 4. Consider modifying the definition of “verification” to “A means of determining or checking that the component is functioning properly or maintenance correctable issues are identified”, eliminate use of the term “verify proper functioning” (which seems to be redundant by PRC-005-2 standard definition), and simply use the term “verify”.
Yes
 
Yes
 
No
1. R4: A “Failure to specify whether a component is being addressed by time-based, condition-based, or performance-based maintenance” by itself is a documentation issue and not an equipment maintenance issue. Suggest this warrants only a lower VSL, especially when one of the required components can only be time based. 2. R4: Suggest a stepped VSL for “Entity has failed to initiate resolution of maintenance-correctable issues”. While we understand the importance of addressing a correctable issue, it seems like there should be some allowance for an isolated unintentional failure to address a correctable issue. If possible, consider the potential impact to the system. For example, a failure to address a pilot scheme correctable issue for an entity that only employs pilot schemes for system stability applications should not necessarily have the same VSL consequence as an entity which employs pilot schemes everywhere on their system as a standard practice.
Yes
 
Yes
 
We support this project and believe it is a positive step towards BES reliability. However, we believe the draft document needs additional work as per our comments. Also, as indicated by the amount of industry input on the last version draft comments, we believe revisions are still needed to properly address this technically complex standard. If this standard is to deviate from the original project schedule and follow a fast track timeline for approval, then we disagree with the 3 month implementation for Requirement 1 and ask for at least 12 months. The original schedule provided sufficient advance notice to work on an implementation plan and it included the typical time required for NERC Board of Trustees and regulatory approvals. If the project schedule and typical NERC Board of Trustees and regulatory approval times are to be accelerated, the implementation plan should be extended.
Individual
James Sharpe
South Carolina Electric and Gas
Yes
Please provide clarity on why Table 1b for “Station dc supply” has a double entry that appears to be contradictory. The table provides monitoring attributes for a maximum maintenance interval of 6 calendar years and the next row says to refer to level 1 maintenance activities.
Yes
 
Yes
(Note that Section C.M2 leaves off "Distribution Provider" but references Requirement R2 at the end of the Section. "R2 applies to the Distribution Provider.")
Yes
 
Yes
 
No
Question/Answer 4-C (Pg. 10 of FAQ) seems to indicate that by documenting breaker operations for fault conditions the table 1b requirements for control circuitry (Trip Coils and Auxiliary relays) can be satisfied. It is possible that even though a breaker successfully operates for a fault condition one trip coil of a primary/backup design can be inoperable and “masked” by the good trip coil. Although it is likely that a faulty trip coil would be caught by monitoring of continuity it is not a certainty that both trip coils actually operated to clear a fault (example-mechanical binding)
R1.1 states “Identify all Protection System Components”. To avoid confusion this should be clarified. It could be interpreted that discreet components must be individually identified. An example would be as individual aux relays used in the tripping path.
Individual
Jon Kapitz
Xcel Energy
The current language is not aligned with the FAQ concerning the level of maintenance required for Dc Systems, in particular the FAQ states that with only 1 element of the Table 1b attributes in place the DC Supply can be maintained using the Table 1b activities, the table itself is clear that ALL of the elements must be present to classify the DC Supply as applicable to Table 1b. The FAQ needs to be aligned with the tables. The FAQ also contains a duplicate decision tree chart for DC Supply. The FAQ contains a note on the Decision tree that reads, "Note: Physical inspection of the battery is required regardless of level of monitoring used", this statement should be placed on the table itself, and should include the word quarterly to define the inspection period.
No comments
No comments
No comments
No
As we commented on in the previous draft of the standard that proposed the Supplementary Reference and FAQ, we are concerned as to what role these documents will play in compliance/auditing. It is also unclear how these documents will be controlled (i.e. Revised and Approved, if at all). Inconsistencies have been identified between proposed standard and the documents (e.g. page 29 of FAQ example 1).
No
As we commented on in the previous draft of the standard that proposed the Supplementary Reference and FAQ, we are concerned as to what role these documents will play in compliance/auditing. It is also unclear how these documents will be controlled (i.e. Revised and approved, if at all). Inconsistencies have been identified between proposed standard and the documents (e.g. page 29 of FAQ example 1).
R1.1 “Identify all Protection System Components” – does this mean that the PSMP must contain a “list”? Please explain what this means. If it is a list, then essentially it will be a dynamic database, not necessarily a “program” as defined in the PSMP R1.3 “include all maintenance activities…” seems to be an indirect way of indicating that the entities PSMP must comply with the tables. Tables – the components related to DC Supply and battery are confusing. It the battery is the specific component then state “battery". If the charger is the specific component, then state “charger”. As currently written, one must sort through all of the different “Station DC Supply” line items to figure out what is required. – In tables 1b and above, it is written “no level 2 monitoring attributes are defined – use level 1 maintenance activities” but then maintenance activities are listed that don’t match with Level 1 maintenance activities. Please clarify what exactly needs to be done if using Table 1 b and above.
Individual
Rex Roehl
Indeck Energy Services
No
 
No
The VRF's are highly arbitrary because they treat all registered entities and all protective systems alike. They're not. For example, under-frequency relays for generators protect the equipment needed to restore the system after a blackout. The under-frequency load relays prevent a cascading outage. 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. That would make under-frequency load relays more important to prevent cascading outages.
No
Measure 1 is complete overkill for a small generating facility. The maintenance program is to inspect and test the equipment within the intervals. A qualified contractor applies industry standard methods to maintain the equipment. Trying to have each entity define the maintenance program down to the component level does not improve reliability.
No
The VSL's treat all entities, components and problems alike. By combining 4 protection maintenance standards, it elevates the VSL on otherwise minor problems to the highest levels of any of the predecessor standards. The threshold percentages are very arbitrary. Severe VSL doesn't in any way relate to reliability. For a small generator to miss or mis-categorize 1 out of 7 relays is unlikely to have any impact on reliability, much less deserving a severe VSL. The R2 & R4 VSL's don't care about results of the program, only whether all components are covered. Half of the components could fail annually and its not a Severe VSL. The R3 VSL allows 4% countable events, which can be hundreds for a large entity and only allows a few for a small entity.
No
In 2.3, the applicability is stated to have been modified. 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 modified applicablity moves away from the purpose of the standards program to an undefined fuzzy concept. Applicable Relays ignore the fact that some relays, or even some entities, have little to no affect on reliability. The global definition of Protective System encompasses all equipment, and doesn't differentiate the components that meet the purpose of the standards program. The Supplementary Reference doesn't overcome the inherent shortcomings of the standard.
No
 
The standard should include an assessment of, and criteria for, determining whether a Protective System is important to reliability. It presently treats a fault current relay on a 345 kV or higher voltage transformer the same as one on a small generator on the 115 kV system. The impact of failures on both on a hot summer day like we've had recently in NY, would be very different. 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. This seems to have been lost in the drafting process. Much of the effort expended on complying with the existing PRC maintenance standards, as well as that to be expended on PRC-005-2, has little to no significant in terms of improving reliability. That effort could be better utilized if focussed on activities that could significantly improve reliability. As one of the Commissioners at the FERC Technical Conference on Standards Development characterized the relationship between FERC and NERC as a wheel off the track. The whole standards program, and especially PRC-005-2, is off the track.
Individual
Jeff Nelson
Springfield Utility Board
No
SUB appreciates the effort to try to strike a balance between specificity around a specific standard and flexibility to meet the requirement under the standard. The maximum allowable intervals don't seem unreasonable combined with the implementation schedule. However, it seems that the proposed changes stray toward a proscriptive set of maintenance that 1) does not allow for an alternate method of testing and 2)sets unrealistic testing requirements. For example, battery terminal to terminal testing is not feasible with all battery systems. This is a consistent message SUB has heard from others as well. First and foremost - a test or maintenance must be done for each device within the defined interval. With that in mind... SUB's preference would be that the maintenance activities focus on what specifically must be done for a device (may be type specific) vs. what could be done for a device for compliance (as an example of what an auditor could look for when conducting an audit) vs. alternative best-practices for testing and maintenance that the entity demonstrates constitutes as maintenance or test. With regard to the first (maintenance activities focus on what specifically must be done for a device) - it seems that this would apply to a limited number of devices With regard to the second (maintenance activities focus on what specifically can be done for a device) - it seems that this would apply broad number of devices and the list of what can be done should be broad to cover a range of different devices that provide the same function. With regard to the last (alternative best-practices for testing and maintenance that the entity demonstrates constitutes as maintenance or test), it would be helpful to have a mechanism outside the standard itself to either have a NERC technical group craft a series of criteria that must be met for an acceptable alternative maintenance or the entity document the criteria used to determine an adequate test and provide for a test that meets that set of criteria). It would be anticipated that these would fall under a minority of devices.
No
Time horizons for implementation seem adequate and SUB appreciates the attention to putting together a reasonable but assertive implementation plan. The Violation Risk Factors are problematic. With all due respect, it seems that NERC still operates in a "BIG UTILITY" mind set. There are "PROTECTION SYSTEMS" and there are "Protection Systems" - some Protection Systems are may significantly impact system reliability and others may not. This not promote reliability in that if an entity was thinking about installing a minor system or installing an improvement that enhances reliability (but is not required) that it might back away because of the risk associated with somehow being out of compliance. Reliability runds the risk of being diminished through the standards approach. SUB suggests stepping back and putting more granularity on VRFs and there needs to be more perspective on the purpose of the device when arriving at a risk factor. Perhaps a voltage threshold could be attached to the VRFs. For example language could be added to say "For Elements at 200kV and above, or for Critical Assets, the risk factor is higher" and "For Elements operating at 100kV and above, the risk factor is medium" and "For Elements below 100kV, the risk factor is lower" In SUB's view, a discussion on VRF's needs to coupled with Violation Severity Levels. SUB discusses VRF's later in this comment form. SUB would be supportive of a Medium VRF designation if there were a more balanced VLF structure (please refer to the comments of VLFs)
No
The measures do not seem unreasonable. However the data retention states that documentation must exist for the two most recent performances of each maintenance activity. Stepping back, there is an implementation schedule that is designed to bring all devices into compliance with ONE maintenance or test within (SUB's understanding is) 6 years. There may not be documentation for more than one activity. Further, new or replacement components won't have more than one activity for a number of years. The data retention schedule, left unchanged, will promote non-compliance because it is impossible to have two records when only one may possibly exist. Rather than promote a culture of compliance, the standard promotes a culture of non-compliance by creating an standard that cannot be met. The FAQ addresses this issue, but the Data Retention language seems to be less clear. SUB suggests that the Data Retention language be clear that new components that do not replace existing components may have only one record for maintenance if only one maintenance of the component could possibly exist. SUB suggests that the Data Retention language also be clear that for new components that replace existing components, that the Data Retention requirement reflect that the entity needs to retain the last test for the pre-existing component and the test for the new component (for a total of two tests).
No
The Violation Risk Factors are problematic. With all due respect, it seems that NERC still operates in a "BIG UTILITY" mind set. Big utilities have potentially hundreds or thousands of components under different device types. Looking at the VRFs, the percentages 5% or 15% as an example, are looked at based on a deep pool of multiple devices so a "BIG UTILITY" that misses a component or small number of components may not trigger a high severity level. However a small utility may have only a handful of components under each type. Therefore if the small utility were to miss one component all of a sudden the utility automatically triggers the 5% or 15% threshold. This type of dynamic unreasonable and not equitable. Therefore (in an attempt to work within the framework proposed), SUB proposes that there be a minimum number of components that might not be in compliance which result in a much lower Violation Severity Level. SUB suggests that NERC try to create a level playing field. If 15% of a Big Utility's total number of components averages at around 15 out of 100 total then perhaps a reasonable outcome would be that up to 5 components (regardless of the total number of components an entity has under each type) could be in violation without tripping into a high VSL. (the 5 components threshold may not apply to all types, this is just for illustrative purposes). Also, are the missed components compounding? For example, if an entity missed 5 components on year three and another 5 components in year 10 is the VSL based on 10 components or 5 components. There should be a time horizon attached to the VSL such that the VSL does not count prior components that were brought into compliance through a past action. That intent may be to not have the VSLs be based on compounding numbers of components, however that should be made clear.
Yes
SUB appreciates that Time Based, Performance Based, and Condition Based programs can be combined into one program. However it should be clear that a utility may include one, two or all three of these types of programs for each individual device type. Currently the language reads: "TBM, PBM, and CBM can be combined for individual components, or within a complete Protection System." The "and" requires all three to be combined if they are combined. SUB suggests the and be changed to "or". Language Change: "TBM, PBM, or CBM can be combined for individual components, or within a complete Protection System."
Yes
 
SUB is supportive of the intent behind the standard and appreciates the ability to provide input into this process. The following is a repeat of the comment in Question #5 with regard to the supplemental reference. SUB appreciates that Time Based, Performance Based, and Condition Based programs can be combined into one program. However it should be clear that a utility may include one, two or all three of these types of programs for each individual device type. Currently the language reads: "TBM, PBM, and CBM can be combined for individual components, or within a complete Protection System." The "and" requires all three to be combined if they are combined. SUB suggests the and be changed to "or". Language Change: "TBM, PBM, or CBM can be combined for individual components, or within a complete Protection System."
Group
Bonneville Power Administration
Denise Koehn
BPA, Transmission Reliability Program
No
The requirements pertaining to dc control circuitry are confusing. To start with, a definition or further explanation is required for the term “auxiliary contact”. Is this strictly a breaker “a” or “b” switch, or does this include lockout relay contacts, etc.? Another confusing point is that the term trip circuit is used in several places throughout the tables, but it is not included in the definition of Protection System, where the term dc control circuitry is used. It is important to use consistent terminology throughout the definition and the standard. The requirements for (dc) control circuits in Table 1a are fairly straightforward, but in Table 1b control circuits are broken down into three parts: trip coils and auxiliary relays; trip circuits; and control and trip circuitry. It is very unclear exactly what each of these three parts includes. In Table 1c, control circuitry is covered as a single element. Please provide clarity to what is included in each part of a control circuit in Table 1b and the monitoring attributes of each. Also, please be consistent in the treatment of control circuits throughout the three tables. Table 1a, SPS, BPA does not understand the following segment of this paragraph “The output action may be breaker tripping, or other control action that must be verified, but may be verified in overlapping segments. A grouped output control action need be verified only once within the specified time interval,..." In one sentence, it says you can test a SPS in segments - and in the next sentence it says you have to verify the grouped output control action at least once within the specified time interval. It seems that the sentences contradict themselves. Table 1b, Control and trip circuitry - "Monitoring of the continuity of breaker trip circuits along with the presence of tripping voltage supply all the way from relay terminals (or from inside the relay) through to the trip coil(s)..." To monitor the trip path as proposed in this Standard would cost some serious time and $$. BPA does not believe there is a way to meet level two monitoring for batteries. In addition, some of the maintenance tasks need to be defined: - monitoring the electrolyte level is not commercially available. - the state of charge of each individual cell may need to be better defined. There are means to verify the state of charge of the entire bank, but not each individual cell. Since a device to provide level 2 monitoring is not commercially available, we would be forced to follow level 1 maintenance guides, which would require maintenance of comm batteries every three months. Many of these batteries are not accessible during 9 months of the year except via sno-cat or helicopter. We currently monitor for some of the level 2 requirements, but not all. Our current practices of monitoring and yearly maintenance supplemented by opportunity inspections have successfully identified problems before we lost DC power to any of our comm facilities. VRLA type batteries: - battery continuity needs to be defined. In regards to the maximum allowable intervals; the frequency with which BPA performs the 18 month maintenance tasks as prescribed in the standard are on a 24 month interval along with visual inspections and voltage measurements weekly to bi-weekly. BPA has seen success with this maintenance program with the ability to identify suspect cells or entire banks with adequate time to perform corrective actions such as repairs or replacements. BPA also does not perform routine capacity testing, this is an as required maintenance task to confirm/validate our other test results if needed. Our suggestion would be to extend the maintenance intervals beyond 18 months, and to provide some clarity on the above items.
Yes
 
Yes
 
Yes
 
 
 
The term “maintenance correctable issue” used in Requirement 4 seems to be at odds with the definition given for it. It seems that an issue that cannot be resolved by repair or calibration during the maintenance activity would be a maintenance non-correctable issue. Also, in Requirement 4, the term “identification of the resolution” is ambiguous. Suggested changes for Requirements 4 and 4.1 are: R4. Each Transmission Owner, Generator Owner, and Distribution Provider shall implement its PSMP, and resolve any performance problems as follows: 4.3 Ensure either that the components are within acceptable parameters at the conclusion of the maintenance activities or initiate actions to replace the component or restore its performance to within acceptable parameters.
Individual
Amir Hammad
Constellation Power Generation
No
Constellation Power Generation (CPG) does not agree with the maximum maintenance interval for associated communication systems and station dc supply that has as a component any type of battery, which is 3 months. If the intent of the drafting team was to make this test quarterly (as recommended in IEEE-450), than the maximum interval should be 4 months. As written, for a registered entity to ensure they complete this test in an interval less than 3 months, they will most likely complete this test every 2 months. This causes two additional and unwarranted tests every year. CPG recommends an alternate formulation for intervals if the nominal interval is less than one year. Some possible alternatives (assuming a three month nominal interval): Once per calendar quarter no later than the end of the quarter no earlier than one month before it. Four times per year, no more than 120 days apart no less than 60. CPG does not agree with differentiating between the different battery types. A suggestion would be to take the maximum maintenance interval for all the battery types, which is 6 years, and apply them across all types of batteries, eliminating the need to differentiate between them. Furthermore, multiple cell units do not provide the ability to measure cell-cell resistance, and so that requirement should be removed. CPG is not clear why electromechanical tip contacts in microprocessor relays are excluded in Table 1a.
No
Constellation Power Generation questions why the VRF for R1 is High while all other requirements are Medium. This VRF should be changed to Medium to follow suit with the other requirements.
No
Constellation Power Generation does not agree with the proposed data retention section. Retaining and providing evidence of the two most recent performances of each distinct maintenance activity should be sufficient. For entities that have not been audited since June of 2007, having to retain evidence from that date to the date of an audit could contain numerous cycles, which is cumbersome and does not improve the reliability of the BES.
No
Constellation Power Generation does not agree with the proposed data retention section. Retaining and providing evidence of the two most recent performances of each distinct maintenance activity should be sufficient. For entities that have not been audited since June of 2007, having to retain evidence from that date to the date of an audit could contain numerous cycles, which is cumbersome and does not improve the reliability of the BES.
Yes
 
No
The PT/CT testing section is implying that the testing must be completed while energized, which is counter to industry practice at generation facilities. Leeway should be given to the entities to devise their own methods for testing voltage and current sensing devices and wiring to the protection system.
Constellation Power Generation does not agree with the changes to Voltage and Current Sensing inputs to protective relays in Table 1a. It is inferring that the only way to complete testing on these components to satisfy NERC is to complete online testing, which is dangerous and does not improve the reliability of the BES. In fact, it can be argued that it decreases the reliability of the BES. The verbiage should be changed back to what was originally proposed to allow for offline testing. Furthermore, Constellation Power Generation does not agree with several of the inclusions of generator Facilities in this standard. For example, in 4.2.5.1, the proposed standard looks to include any components that can trip the generator. At a nuclear facility, this could include protection of motors at the 4 kV level that may trip the generator due to NRC regulated safety issues. This should not fall under NERC jurisdiction. The inclusion of station service transformers is another inclusion that should not be in this standard. There is no difference between a station service transformer and a transformer serving load on the distribution system. This has no impact on the BES, which is defined as the system greater than 100 kV. Additionally, CPG has concerns regarding the vague language of R1.1, which requires the identification of all protection systems components. It provides no elaboration on the level of granularity expected or acceptable means of identification. It is unlikely that the SDT expected the unique identification of every discrete component down to individual test switches or dc fuses. In the case of current transformers, several of which, or even dozens of which may be connected to a single relay there is no apparent reliability benefit that comes from identifying them uniquely so long as it is proven that a protection system is receiving accurate current signals from the aggregate connection. (It may be argued that the revised definition of “protection stems” eliminates the need to include CT’s under R1.1 but that’s just one interpretation.) Some discrete components of communication systems may exist in an environment that is not owned by or known to the protection system owner. Additionally all protection system components may be identified in documents that are current and maintained but not in the form of a specific search-able list that is limited to components that are within the scope of PRC-005. Examples may be indexed engineering drawings that identify relays and other components for each protection systems or scanned relay setting and calibration documents that are current but not attached to search-able meta data. It is unclear whether or not these would be considered acceptable identification meeting R1.1. If they are not then the implementation plan for R1 is in all probability unachievable. CPG requests that the SDT provide more elaboration on R1.1 in the standard and in the supporting documents. In that vein, to clarify footnote 1 to R1 which excludes devices that sense non-electrical signals, it should explicitly say that the auxiliary relays, lockout relays and other control circuitry components associated with such devices are included. The matter is well-addressed in the FAQ’s but could easily be misunderstood if not included here. Lastly, Constellation Power Generation would like to voice concern over the expedited process in which this standard is being developed. Voting within a week of submitting comments does not leave enough time for the drafting team to thoroughly vet through the issues and identify much needed changes, let alone implement them.
Group
WECC
Tom Schneider
Western Electricity Coordinating Council
Yes
Compliance agrees with the changes as they add clarity though the Tables do not define what is actually required to demonstrate compliance without reading the Supplementary Reference and the FAQs.
 
Compliance agrees with the measures. Compliance recommends making the Supplementary Reference part of the standard and that it be referenced appropriately in Table 1a, 1b, 1c and Attachment A. Compliance does not agree with the Data Retention as provided in the draft. In order for an entity to demonstrate that they have maintained system protection elements within their defined intervals retention of documentation will be required for many years. This is in order to establish bookends for the maintenance interval. Maintenance intervals commonly span 5 years or more. Entities should be required to retain data for the entire period of the maintenance interval. Data Retention should be changed to: The Transmission Owner and any Distribution Provider that owns a transmission Protection System and each Generation Owner that owns a generation Protection System, shall retain evidence of the implementation of its Protection System maintenance and testing program for a minimum of the duration of one maintenance interval as defined in the maintenance and testing program.
No
Compliance does not agree. The R1 VSL allows too much to interpret. What does no more than 5% of the component actually use to define the percentage; it should be specific if it is referring to the weight of each component and how many components are there. For example, Protective Relay is one component of five. In addition the VSL for Lower, Moderate and High states in the first paragraph that the entity included all of the “Types” of components according to the definition, though failed to “Identify the Component”. It needs clarity on how it can be included though not specifically identified like the next two bullets. The same concern applies to R2 and R4. Be specific about what is included (or not) to calculate those percentages.
Yes
Compliance does agree with the clarity and the Supplementary Reference should be specially referenced where appropriate the Tables 1a, 1b, 1c and Attachment A that are included with the Standard. But this reference is not a part of the approved standard and there are no controls which prevent changes in the reference document that could impact the scope or intent of the standard. If the standard is approved with reference to the Supplementary Reference then future changes to the Supplementary Reference should not be allowed without due process. Only the version in existence at the time of approval of the standard could be used to clarify or explain the standard.
Yes
Compliance does agree with the clarity. The FAQ answers should be referenced specifically to the Standard and the Supplementary Reference to further understand those two documents. However, endorsement of the Standard should not imply endorsement of the FAQ and vice versa.
Compliance believes it will be difficult to demonstrate compliance when an entity chooses Condition Based Level 2 or Level 3 maintenance as the details of the requirements are still open to interpretation. The FAQ has answers to specific questions that are multiple choices. Breaking down this standard into this level of granularity requires supplementary documents to understand it and for auditors to understand how to determine compliance. Industry standards are specific to equipment types and should be allowed to set intervals and maintenance tasks rather than a one-size fitting all approach.
Group
Western Area Power Administration
Brandy A. Dunn
Western Area Power Administration - Corp Services Office
No
1) Standard, Table 1a, “Control and trip circuits with electromechanical trip or aux contacts (except for microprocessor relays, UFLS or UVLS)”: Where would un-monitored control and trip circuits connected to a microprocessor relay fall, and what is the associated interval and maintenance activity? 2) Standard, Table 1a, “Control and trip circuits with electromechanical trip or aux contacts (except for microprocessor relays, UFLS or UVLS)”: Please confirm that the defined Maintenance Activity requires actual tripping of circuit breakers or interrupting devices. 3) Standard, Table 1a, “Control and trip circuits with unmonitored solid state trip or auxiliary contacts (except UFLS or UVLS)”: Please confirm that the defined Maintenance Activity requires actual tripping of circuit breakers or interrupting devices. 4) Standard, Table 1b. On page 13, for Protective Relays, please clarify the intent of “Conversion of samples to numeric values for measurement calculations by microprocessor electronics that are also performing self diagnosis and alarming.” 5) Standard, Table 1b. On page 13, for Protective Relays, please clarify the intent of “Verify correct operation of output actions that used for tripping.” Does this require functional testing of a microprocessor relay, i.e., using a relay test set to simulate a fault condition? 6) Standard, Tables 1a and 1b: Would it be possible to provide an interval credit for full parallel redundancy from relay to trip coil? 7) Table 1a (page 9) Voltage and Current Sensing Inputs to Protective Relays and associated circuitry – This maintenance activity statement implies that signal tests to prove the voltage and current are present is all that is required. Can this be accomplished by adding a step to the Relay Maintenance Job Plan to take a snapshot of the currents and potentials (In-Service Read) with piece of test equipment? 8) Table 1b (Page 14) Control and Trip Circuitry – Level 2 Monitoring Attributes for Component is too wordy and hard to understand the meaning. Does this whole paragraph mean that the dc circuits need to be monitored and alarmed? At what level does the dc control circuits need the alarming? Can this be at the control panel dc breaker output? 9) Table 1b (Page 15) Station Dc Supply – Should this be in Table 1c because the attributes indicate that the station dc supply cells and electrolyte levels are monitored remotely. To do a fully monitored battery system would be cost prohibitive and require a tremendous amount of engineering. 10) Table 1a and 1b (Page 11 and 16) Associated communications system - Western has monitoring capability on all Microwave Radio and Fiber Optics communications systems with the Communications Alarm System that monitors and annunciates trouble with all communications equipment in the communications network. The protective relays that use a communications channel on these systems have alarm capability to the remote terminal units in the substation. Since these are digital channels how does an entity prove channel performance on a digital system?
Yes
 
Yes
 
Yes
 
Yes
 
Yes
Clarification 1) FAQ, page 36, Control Circuit Monitor Level Decision Tree: It’s not clear if the note on Level 1 device operation is required for Level 3 monitoring.
1) Standard, Page 4, R 4.3: Is the utility free to define its own “acceptable limits”? 2) Standard, Page 4, R 4.3: Must the “acceptable limits” be stated in the PSMP? 3) Standard, Page 4, Footnotes 2 and 3 are the same. 4) Attachment A says we can go to a performance based program; does this apply to every part of the standard? In other words, does this apply to component testing, functional testing, etc., and do we define the intervals of the test. That is, do we determine how long we test the sample of at least 30 units that Attachment A discusses?
Group
Public Service Enterprise Group ("PSEG Companies")
Kenneth D. Brown
Public Service Electric and Gas Company
No
The SDT is to be commended for the work and details included in the most recent draft revision. The standard – with associated references is easier to interpret. The sections on DC supply are too restrictive. Quartile checks of VLA electrolyte levels for unmonitored systems is reasonable, however the option of checking the electrolyte levels and voltages with less frequency is not an option with systems that have voltage alarm notification and ground detection monitoring alarm notification unless all level 2 attributes are followed. The level 2 monitoring attributes are too comprehensive to allow for a suggested alternative less restrictive interval of 6 months to a year. Suggest there be an additional option for level 2 monitoring that includes voltage level and ground alarms with a 6 month maintenance activity interval. The perception of table 1a page 12 for station DC supply – “used for UVLS and UFLS” is a maintenance activity to verify proper DC supply voltage when the UVLS and UFLS system is maintained. This is the only DC supply maintenance activity for those applications and the other more rigorous maintenance activities do not apply? If this is a correct interpretation specifically list that as such in the maintenance activity description (State the other DC supply maintenance activities are not applicable for UVLS and UFLS). The maintenance intervals for station DC supply for level 1 and 2 monitoring does not appear to be consistent and is somewhat confusing. A battery system with level 2 monitoring attributes for components has intervals of 6 years, and then in next section states that no level 2 attributes are defined - use level 1 maintenance activities. Suggest that all DC supply / batteries be broken out all be included in one separate -stand alone table with varied maintenance requirements based on monitoring attributes. The maintenance activities shown on table 1b on page 19 for Station DC supply is intended for VLA batteries? If so add that in component definition. For DC systems that use a storage battery, suggest that chargers be eliminated as other required maintenance activities will expose any problems with the charger. The requirements of performing a capacity test every 6 years during the initial service life of a VLA battery in addition to the other maintenance activities are too restrictive and will cause extensive outages of the affected equipment. Suggest that this frequency be extended to 10 years for VLA batteries for the first iteration if all the other maintenance activities are followed. Failure rate of VLA in first 10 years is extremely low. Other maintenance activities will expose significant issues.
Yes
 
No
Data retention for battery capacity test should be most recent performance, not last 2. The other maintenance activities documentation with one iteration of capacity test is sufficient documentation
Yes
 
No
Suggest that figure 2 has a line of demarcation added that shows components specifically not part of the standard requirements. (Medium voltage bus). Battery charger should be removed from table of components when a storage battery is used for the DC supply.
No
This is a very useful document and provides a good source of additional information; there are some cases where it could be interpreted as a standard requirement that can lead to confusion if conflicts exist. For example, the group by monitoring level example V.1.A shown on page 29 describes a level 2 partial monitoring as circuits alerting a 24Hr staffed operations center, page 38 shows level 2 monitoring as detected issues are reported daily. The actual standard table 1b level 2 monitor describes alarms are automatically provided daily to a location where action can be taken for alarmed failures within 1 day or less. This is listed as a supplemental reference document in the standard. The FAQ document “supports” the standard but is or is not an official interpretation tool, or if it is state as such.
 
Individual
Gerry Schmitt
BGE
No
Comment 1.1: In its decision to use “calendar years” with the maintenance intervals prescribed for most components the SDT has provided a framework that is consistent with a well-run PSMP but with enough flexibility to be practical. However BGE believes the application of this approach to short maintenance intervals, like three months for some battery maintenance will risk numerous violations due to practical scheduling constraints that are not a realistic threat to reliability. As the requirements are presently defined the inherent flexibility for battery maintenance that is nominally done on three month intervals may be as long as 1/3 of the interval or as short as one day (Our interpretation: Maintenance last done on January 1 is next due on April 1 and can be done no later than April 30. Maintenance done on Jan 31 is next due on April 30 and is overdue if done on May 1). The only practical solution is to increase the frequency so that the average intervals are significantly shorter than the nominal requirement. BGE recommends an alternate formulation for intervals if the nominal interval is less than one year. Some possible alternatives (assuming a three month nominal interval): Once per calendar quarter no later than the end of the quarter no earlier than one month before it. Four times per year, no more than 120 days apart no less than 60. Comment 1.2: On page 11, Row-3/Column-1 of Table-1a includes the following entry for functional trip testing: "Control and trip circuits with electromechanical trip or auxiliary contacts (except for microprocessor relays, UFLS or UVLS)". It is not clear why electromechanical trip contacts in microprocessor relays are excluded. Comment 1.3: On page 12, Row-3/Column-3 of Table-1a includes the following Verification Task for Station DC Supplies: "Verify Battery cell-to-cell connection resistance". Multiple cell units do not provide the ability to measure cell-cell resistance.
No
See comments under 7 regarding the ambiguity of R1.1. A high VRF for some interpretations of R1.1 may not be reasonable. A program may be structured so that sufficient maintenance to ensure reliability is taking place even though a specific component is not identified. Contrasting the high VRF for R1 with the medium VRF for R4 seems backwards.
Yes
 
No
The VSL’s as proposed may be reasonable but it is difficult to endorse them until the ambiguity in R1.1 is reduced.
Yes
 
No
The FAQ is a very helpful document. A few more changes would be beneficial. See comments regarding manufactures’ advisories and R1.1 under section 7 below. It is our recommendation that manufacturers service advisories not be an implied part of the PMSP requirements and that the expectations for R1.1 be more explicitly described in the FAQ.
Comment 7.1 The standard, FAQs, and supplementary reference all make references to upkeep and include in “upkeep” changes associated with manufacturer’s service advisories. The FAQs include statements that the entity should assure the relay continues to function after implementation of firmware changes. This statement is uncontestable as general principle but is problematic in its inclusion in an enforceable standard because there is no elaboration on what the standard expects, if anything, as demonstration of an entity’s execution of this responsibility. PRC-005-2 appropriately focuses on implementation of time-based, condition based, or performance based PSMPs; but addressing service advisories does not fit well with any of these ongoing preventive maintenance activities. It is instead episodic, more like commissioning after upgrades, or corrective maintenance work generated by condition-based alarms or anomalies discovered by analyzing operations. The standard appropriately steers clear of imposing requirements for these latter responsibilities as long as execution of an ongoing maintenance program is being demonstrated. BGE recommends that implied inclusion of service advisories should be removed from the standard and supporting documents. Comment 7.2 R1.1 Requires the identification of all protection systems components. But it provides no elaboration on the level of granularity expected or acceptable means of identification. It is unlikely that the SDT expected the unique identification of every discrete component down to individual test switches or dc fuses. In the case of current transformers, several of which, or even dozens of which may be connected to a single relay there is no apparent reliability benefit that comes from indentifying them uniquely so long as it is proven that a protection system is receiving accurate current signals from the aggregate connection. (It may be argued that the revised definition of “protection systems” eliminates the need to include CT’s under R1.1 but that’s just one interpretation.) Some discrete components of communication systems may exist in an environment that is not owned by or known to the protection system owner. Additionally all protection system components may be indentified in documents that are current and maintained but not in the form of a specific searchable list that is limited to components that are within the scope of PRC-005. Examples may be indexed engineering drawings that indentify relays and other components for each protection systems or scanned relay setting and calibration documents that are current but not attached to searchable metadata. It is unclear whether or not these would be considered acceptable identification meeting R1.1. If they are not then the implementation plan for R1 is in all probability unachievable. BGE requests that the SDT provide more elaboration on R1.1 in the standard and in the supporting documents. Comment 7.3 For clarity footnote 1 to R1 which excludes devices that sense non-electrical signals should explicitly say that the auxiliary relays, lockout relays and other control circuitry components associated with such devices are included. The matter is well-addressed in the FAQ’s but could easily be misunderstood if not included here.
Individual
Michael R. Lombardi
Northeast Utilities
No
In Table 1c it is required to report the detected maintenance correctable issues within 1 hour or less to a location where action can be taken to initiate resolution of that issue. Even for a fully monitored protection system component it can be difficult to report the action in 1 hour. Recommend a 24 hour period for both Level 2 and Level 3 reporting of maintenance correctable issues. Additionally, please clarify meaning of “to a location where action can be taken”.
Yes
 
No
Two most recent performances of each distinct maintenance activity for the Protection System components will require data retention for an extended period of time. From the FAQ, it is understood that “the intent is not to have three test result providing two time intervals, but rather have two test results proving the last interval”. However two intervals still results in an extended period of time. For example, for a twelve year interval, data would need to be retained for ~24 years. During that period of time a number of on-site audits would have been completed - it is not clear why the requirement is the longer of the two most recent performances or to the previous on site audit date.
No
For R1 under Severe VSL – suggest moving the first criteria “The entity’s PSMP failed to address one or more of the type of components included in the definition of “Protection System” under High VSL since this criteria cannot have the same VSL level as “Entity has not established a PSMP”.
No
There is no guidance on how to calculate the total number of components and thus, the percentages under different severity levels. FAQ provides some insight into how an entity can count components however; an example in the reference document will provide clarity.
No
Page 2 under Component definition, term “somewhat arbitrary” is used by the drafting team to address what constitutes a dc control circuit. Though the drafting team has provided entities with flexibility to define as per their methodologies, it is recommended to clearly determine “what constitutes a dc control circuit” since it will be used to determine compliance.
R1.1 It is not clear what would constitute “all Protection System components”. Suggest the addition of a definition for “Protection System components”. R1.4 Suggest revise to read: “all batteries or dc sources” Table 1a vented lead acid -- “Verify that the station battery can perform as designed by evaluating …” -- Please define evaluating, including: • What is the basis for the evaluation? • Is 5% 10% 20% etc acceptable? • Where does baseline come from for older batteries? Request clarification of 2.3 Applicability of New Protection System Maintenance Standards from Supplementary Reference. Specifically, please clarify if a functional trip test is needed to be performed on the distribution circuit breakers to protect the Bulk Electric System (BES) if these low side breakers are not part of the transmission path. (A diagram identifying the applicable breakers would be helpful in the Supplementary Reference)
Individual
Jeff Kukla
Black Hills Power
No
-For Protective Relays, Table 1a Maintenance Activities has no requirement for verifying output contacts on non-microprocessor based relays. The actual contacts used for tripping should be verified by this activity. -For Protective Relays, Table 1b Maintenance Activities states “Verify correct operation of output actions that are used for tripping”. This requirement is vague and needs to define whether all protection logic or conditions that would initiate a relay trip output are required to be simulated and tested to the relay tripping output contact. -For Voltage and Current Sensing Inputs to Protective Relays and associated circuitry, Table 1a references “current and voltage signals” and Table 1b references “current and voltage circuit signals”. Need consistency or definitions to meet this requirement. -For Control and trip circuits with electromechanical trip or auxiliary (UFLS/UVLS Systems Only), Table 1a states “..except that verification does not require actual tripping of circuit breakers or interrupting devices.” This exception to the requirement seems to defeat the whole purpose of the standard and leaves a huge gap open to interpretation and conflict. -For Control and trip circuits with unmonitored solid-state trip or auxiliary contacts (UFLS/UVLS Systems Only), Table 1a states “..except that verification does not require actual tripping of circuit breakers or interrupting devices.” This exception to the requirement seems to defeat the whole purpose of the standard and leaves a huge gap open to interpretation and conflict. -For Station dc supply, Table 1a requirement includes “Inspect: The condition of non-battery-based dc supply.” This is redundant with the requirements of the section Station dc supply (battery is not used) and should be removed from this section. -For Voltage and Current Sensing Inputs to Protective Relays and associated circuitry, a maximum interval of verification of 12 years seems to contradict the intent of the rest of the Maintenance standard which dictates 6 years on all of the other components. The requirement for these components should fall in line with the rest of the standard.
No
-Why would R1 (PSMP Program Establishment) be a HIGH VRF and R4 (the actual implementation of the plan) be a medium VRF? These two requirements need to have the same implementation and severity.
Yes
 
No
-VSL's are based on percentages of components, where the definition of a 'component' is in many cases up to the entity to interpret (see PRC-005-2 FAQ sheet, Page 2). Basing VSL's on an entities interpretation (or count) of 'components' is not an equitable measure of severity level.
Yes
 
Yes
 
 
Individual
John Bee
Exelon
No
Exelon does not completely agree with the minimum maintenance activities and maximum allowable intervals as suggested by SDT. Comments on minimum maintenance activities: Reference Table 1a (Page 11) of Standard PRC-005-2: With regard to the maintenance activity: "Verify that the station battery can perform as designed by conducting a performance ……". The standard should clearly define what is meant by "perform as designed" to eliminate ambiguity in future interpretations. Also, Table 1a Station dc supply (that has as a component Vented Regulated Lead-Acid batteries) discusses “modified performance capacity test of the entire battery bank”. This needs additional clarification or should be reworded because modified test includes both the performance test (which is the capacity test) and the service test. Should be reworded to be “modified performance test”. Comments on maximum allowable intervals: Nuclear generating stations have refueling outage schedule windows of approximately 18 months or 24 months (based on reactor type). If for some reason the schedule window shifts by even a few days, an issue of potential non-compliance could occur for scheduled outage-required tasks. The possibility exists that a nuclear generator may be faced with a potential forced maintenance outage in order to maintain compliance with the proposed standard. For the requirements with a maximum allowable interval that vary from months to years (including 18 Months surveillance activities), the SDT should consider an allowance for NRC-licensed generating units to default to existing Operating License Technical Specification Surveillance Requirements if there is a maintenance interval that would force shutting down a unit prematurely or face non-compliance with a PRC-005 required interval. Therefore, Tables 1a, 1b & 1c should include an allowance for any equipment specifically controlled within each licensee’s plant specific Technical Specifications to implement existing Operating License requirements if such a conflict were to occur. Please see additional comments under Q7.
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Nuclear generators are licensed to operate and regulated by the Nuclear Regulatory Commission (NRC). Each licensee operates in accordance with plant specific Technical Specifications (TS) issued by the NRC which are part of the stations’ Operating License. TS allow for a 25% grace period that may be applied to TS Surveillance Requirements. Referencing NRC issued NUREGs for Standard Issued Technical Specifications (NUREG-143 through NUREG-1434) Section 3.0, "Surveillance Requirement (SR) Applicability," SR 3.02 states the following: "The specified Frequency for each SR is met if the Surveillance is performed within 1.25 times the interval specified in the Frequency, as measured from the previous performance or as measured from the time a specified condition of the Frequency is met." The NRC Maintenance Rule (10 CFR 50.65) requires monitoring the effectiveness of maintenance to ensure reliable operation of equipment within the scope of the Rule. Adjustments are made to the PM (preventative maintenance) program based on equipment performance. The Maintenance Rule program should provide an acceptable level of reliability and availability for equipment within its scope. The NRC has provided grace periods for certain maintenance and surveillance activities. Exelon strongly believes that SDT should consider providing this grace period to be in agreement and be consistent with the NRC methodology. Not providing this grace period will directly affect the existing nuclear station practices (i.e., how stations schedule and perform the maintenance activities) and may lead to confusion as implementing dual requirements is not the normal station process. Nuclear generating stations have refueling outage schedule windows of approximately 18 months or 24 months (based on reactor type). If for some reason the schedule window shifts by even a few days, an issue of potential non-compliance could occur for scheduled outage-required tasks. The possibility exists that a nuclear generator may be faced with a potential forced maintenance outage in order to maintain compliance with the proposed standard. For the requirements with a maximum allowable interval that vary from months to years (including 18 Months surveillance activities), the SDT should consider an allowance for NRC-licensed generating units to default to existing Operating License Technical Specification Surveillance Requirements if there is a maintenance interval that would force shutting down a unit prematurely or face non-compliance with a PRC-005 required interval. Therefore, at a minimum, maintenance intervals should include an allowance for any equipment specifically controlled within each licensee’s plant specific Technical Specifications to implement existing Operating License requirements if such a conflict were to occur. 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
Andrew Z.Pusztai
American Transmission Company
No
ATC feels additional changes are needed. The functional testing requirement should be altered or removed as it increases the amount of hands-on involvement and the opportunity for human error related outages to occur, thereby introducing more opportunities to decrease system reliability. As noted on p. 8 in the supplementary reference document, “Experience has shown that keeping human hands away from equipment known to be working correctly enhances reliability.” By removing circuits from service on the proposed timelines for functional testing, the chance for human error is greater than a mis-operation from faulty wiring. Alternatively, entities may choose to schedule more planned outages to conduct their functional testing in order to limit the risk of unplanned outages resulting from human error. Under this scenario, more elements will be scheduled out of service on a regular basis, thereby reducing transmission system availability and weakening the system making it more challenging to withstand each subsequent contingency (N-1). Thus testing an in-tact system is more desirable than taking it out of service for testing. While the SDT has included language in the draft standard to use fault analysis to complete maintenance obligations, in practicality, this option does not offer any relief to taking outages to perform functional tests. Nearly all BES circuit breakers are equipped with dual trip coils. Identifying which trip coil operated for a fault only covers the one trip coil. Functional tests would still be needed on the other. The likelihood of having multiple trips on a given line in the course of several years is very low. Given it can take a year to schedule some outages, planning maintenance with random faults is unpractical and will create unacceptable risk to compliance violations. A better approach is to use the basis in schedule A, but extend this to cover the entire protection schemes. The document should establish target goals for mis-operation rates (dependability and security). This would allow the utilities to develop cost effective programs to increase reliability. The utilities would have incentives to replace poorly performing communications systems; they would be able to quantify the value of upgrading relay systems.
No
ATC disagrees with the VRFs as specified in the standard. R1 VRF would more likely be classified as “medium” and R2 through R4 should be classified as a “High” VRF. ATC is O.K. with the Time Horizons specified.
No
The NERC standard assigns a retention period for the two most recent performances of maintenance activity which implies two intervals of documentation be maintained. ATC does not agree that requiring all data for two full cycles is warranted. The volume and length of data retention is unreasonable. ATC recommends that the entity retain the last test date with the associated data, plus the prior cycle test date only without retaining the test data. ATC agrees with assignment of the measures.
Yes
 
Yes
 
No
The FAQs are helpful, however, with the revised standard as written, ATC has issues with the answers provided. Please refer to Question #7 for areas of concern.
It is appreciated that the SDT is attempting to provide options for maintenance and testing programs. Practically speaking, it will be difficult to perform any type of program outside of Time-Based Maintenance (TBM). Too many circuits are a mix of technology. For example, a line may have microprocessor relays for detecting and tripping line faults, but the bus differential lockout could also trip the line breaker. One may be partially monitored and the other unmonitored. It will force the utility to perform maintenance at the shorter of the maintenance cycles. Additional time and cost will be required to organize and switch out the applicable equipment for the outage, approximately doubling the cost associated with performing these trip tests. When entities are required to maintain tens of thousands of these devices, the simplest approach will be to revert to TBM. ATC does not support the existing 2nd Draft of PRC-005-2 Standard because it is our opinion that: • There is a high probability that system reliability will be reduced with this revised standard. • The number of unplanned outages due to human error will increase considerably. • Availability of the BES will be reduced due to an increased need to schedule planned outages for test purposes (to avoid unplanned outages due to human error). • To implement this standard, an entity will need to hire additional skilled resources that are not readily available. (May require adjustments to the implementation timeline.) • The cost of implementing the revised standard will approximately double our existing cost to perform this work. ATC requests that relevant reliability performance data (based on actual data and/or lessons learned from past operating incidents, Criteria for Approving Reliability Standards per FERC Order 672) be provided to justify the additional cost and reliability risks associated with functional testing. Under a Performance-Based Program, what happens if the population of components drops below 60 (as all will eventually)? Is there an implementation period to default to TBM? Are the internal relays and timers associated with a circuit breaker included as part of the protection scheme? In the Independent Pole Operation breakers (IPO), there are various internal schemes built to protect for pole discordance (one pole open, two closed, event measured over time frame (milliseconds)), these schemes may re-trip the breaker, initiate breaker failure protection or trip a bus lock out relay. In DC control schemes fuses and panel circuit breakers protect for wiring faults. Do these devices need to be tested? Is there an obligation to test the distribution circuit breakers for correct operation points? Is there an obligation to replace fuses after a defined time period?
Individual
Thad Ness
American Electric Power
No
In Table 1a for the component “Station dc Supply (used only for UVLS and UFLS)”, the interval prescribed is "(when the associated UVLS or UFLS system is maintained)" and the activity is to "verify the proper voltage of the dc supply". The description of the interval "(when the associated UVLS or UFLS system is maintained)" needs to be changed. Relay personnel do not generally take battery readings. The interval should read “according to the maximum maintenance interval in table 1a for the various types of UFLS or UVLS relays". The testing does not need to be in conjunction with the relay testing, it is only the test interval that is important, although relay operation during relay testing is a good indicator of sufficient voltage of the battery. The monitoring and/or maintenance activities listed for batteries are not appropriate in Tables 1b and 1c. There are no commercial battery monitors that monitor and alarm for electrolyte level of all cells. Why not move the electrolyte level to the 18 month inspection and actually open the possibility of condition monitoring to commercially available devices? Or give an option to do the electrolyte check at other time intervals (perhaps 12 months) by visual electrolyte inspection and still allow the monitoring of other functions on the listed 6 year schedule using condition monitoring. It makes no sense to prescribe an unattainable condition monitoring solution. The way that the tables are written, there is no advantage to use the charger alarms since battery maintenance requirements are not reduced in any way.
Yes
 
No
The measure includes the entire definition of "Protection System". Remove the definition from the measure and let the definition stand alone in the NERC glossary. 1.3 Data Retention This calls for past 2 distinct maintenance records to be kept. Since UFLS interval can be 12 years, this would mean that we would need to keep records for 24 years. This is not realistic and consideration should be given to choosing a reasonable retention threshold.
Yes
 
Yes
 
Yes
 
The "Supplementary Reference" and the "Frequently-Asked Questions" document should be combined into a single document. This document needs to be issued as a controlled NERC approved document. AEP suggests that the document be appended to the standard so it is clear that following directions provided by NERC via the document are acceptable, and to avoid an entity being penalized during an audit if the auditor disagrees with the document’s contents. NiCAD batteries should not be treated differently from Lead-Acid batteries. NiCAD battery condition can be detected by trending cell voltage values. Ohmic testing will also trend battery conditions and locate failed cells (although will usually lag behind cell voltages). A required load test is detrimental to the NiCAD manufacturer's business, and will definitely hurt the NiCAD business for T&D applications. Historically NiCADs may have been put into service because of greater reliability, smaller space constraints, and wider temperature operation range. “Individual cell state of charge” is a bad term because it implies specific gravity testing. Specific gravity cannot be measured automatically (without voiding battery warranty or using an experimental system), and when it is measured, it is unreliable due to stratification of the electrolyte and differing depths of electrolyte taken for samples. “Battery state of charge” can be verified by measuring float current. Once the charging cycle is over the battery current drops dramatically, and the battery is on float, signaling that the battery has returned to full state of charge. This is an appropriate measure for Level 3 monitoring as float current monitoring is a commercially viable option and electrolyte level monitoring is not. In Table 2b, why is Ohmic testing required if the battery terminal resistance is monitored? Cell to cell and battery terminal resistance should not be monitored because they will be taken in 18 month intervals. This further supports the argument that the battery charger alarms would be sufficient for level 2 monitoring, while keeping an 18 month requirement for Ohmic testing, electrolyte level verification, and battery continuity (state of charge). Automatic monitoring of the float current should be sufficient for level 3 monitoring as it gives state of charge of the string, and battery continuity (detect open cells). Shorted cells will still be found during the Ohmic testing and a greater interval is sufficient to locate these problems.
Individual
Barb Kedrowski
We Energies
No
Table 1a, Protective Relays: Change 1st line to: “Test and calibrate if necessary the relays…” Table 1a, Protective Relays: 3rd line: Change “check the relay inputs…” to “verify the relay inputs…”. The term “check” is not defined, whereas “verify” is. Tables 1a & 1b We agree that six / twelve years is an acceptable interval for relay maintenance. Table 1a & 1b, Control & Trip Circuits: The proposed addition to require tripping circuit breakers during Protection System maintenance is detrimental to BES reliability and should be removed.  Generating unit protection system maintenance is done during scheduled outages. The high voltage breaker on a generating unit often remains energized to backfeed and supply station auxiliaries when the generator is offline. The proposed requirement will increase the amount of equipment requiring an outage for maintenance, and possibly the length of the outage, resulting in significantly more equipment out of service as well as increased costs. This requirement also results in greater maintenance efforts and costs when there are redundant protection system equipment (breaker trip coils, lockout relays, etc), which is contrary to good practice and reliability.  Many of the breakers that We Energies, as the Distribution Provider, trips from its BES protection systems are not owned by We Energies and are owned by a separate transmission company. The trip testing and maintenance of the transmission company may not coincide with our relay maintenance testing program. The standard shall have allowances for the entity to ONLY test or maintain equipment that it OWNS! Table 1a, Station dc supply:  The activity to verify the state of charge of battery cells is too vague, and requires more specific action. We assume that the drafting committee is recommending specific gravity measurements. Specific gravity measurements have not been shown to an accurate indicator on state of charge. In addition, as shown in the nuclear power industry, there is no established corrective action that is taken based on specific gravity results (eg. Don’t require a test where there is no acceptable corrective action).  The activities to “verify battery continuity” and “check station dc supply voltage” are also vague and need to be more clearly specified what is intended.  The 3 month time interval for battery impedance testing is too frequent. 18 month or annual testing is more appropriate.  The 3 calendar year performance or service test is too frequent and will actually remove life from a battery and reduce reliability. Recommend capacity testing no more that every 5 years and more frequent test if the capacity is within 10% of the end of life or design. This is consistent with the nuclear power industry. Table 1b, Station dc supply:  Recommend a change or addition to Table 1b - Recommend a level 2 monitoring (not just a default to the level 1 maintenance activities) which allows for the removal of quarterly “check” of electrolyte levels, DC supply voltage, and DC grounds - if station DC supply (charger) voltage is continuously monitored (eg. one should not have detrimental gassing of a battery if the float voltage of the battery is properly set and monitored). Table 1a, Associated communications systems: The requirement to verify functionality every three months is excessive; verifying this every twelve months is adequate. Tables 1a & 1b – Although the latest standard provided some additional clarification, more clarification is required on what maintenance / testing is ONLY required for UFLS/UVLS protection systems vs. BES protection systems (eg. UFLS / UVLS systems – Is a verification of proper voltage of the DC supply the only battery or DC supply required (eg. no state of charge, float voltage, terminal resistance, electrolyte level, grounds, impedance or performance test, etc.)?
Yes
 
No
The requirement to retain data for the two most recent maintenance cycles is excessive. The required data should be limited to the complete data for the most recent cycle, and only the test date for the previous cycle.
Yes
 
Yes
 
Yes
 
 
Group
FirstEnergy
Sam Ciccone
FirstEnergy Corp.
No
We support most of the maintenance activities detailed in the Tables, but question the verification of battery cell-to-cell resistance. On some types of battery units, this internal connection is inaccessible. We suggest substituting "unit-to-unit" in place of "cell-to-cell".
No
Although we agree that Requirement 1 is important because it establishes a sound PSMP, a HIGH VRF assignment is not appropriate and it should be changed to LOWER. By definition, a requirement with a LOWER VRF is administrative in nature, and documentation of a program is administrative. Assigning a LOWER VRF to R1 is more logical since R4, which is the requirement to implement the PSMP, is assigned a MEDIUM VRF because, if violated, it could directly affect the electrical state or the capability of the bulk electric system. Additionally, revising the VRF to LOWER would provide a consistent assignment to a VRF on a similar requirement in the proposed FAC-003-2 standard.
Yes
We agree with the Measures but suggest some improvements: 1. In Measures M2 and M3, the term "should" must be changed to "shall" 2. In Measure M2, the Distribution Provider entity is missing
Yes
 
Yes
We support the reference document and appreciate the SDT's hard work developing this document. We offer the following suggestions for possible improvements: 1. The reference document should be linked in Section F of the standard. Otherwise it may be difficult for someone to navigate the NERC website in search of the document. 2. Section 2.2 – It would be helpful if a short discussion of the reasons for the changes to the definition of Protection System was included in this reference document. In addition, it would be beneficial to discuss what is included in "dc supply" components, such as "dc supplies include battery chargers which are required to be maintained per the Tables in PRC-005-2." 3. Section 8.1 – The fourth bullet which reads "If your PSMP (plan) requires more then you must document more." Should be removed. This is already covered in the sixth bullet which states "If your PSMP (plan) requires activities more often than the Tables maximum then you must document those activities more often."
Yes
We support the FAQ document and appreciate the SDT's hard work developing this document. The reference document should be linked in Section F of the standard. Otherwise it may be difficult for someone to navigate the NERC website in search of the document.
Implementation Plan a. We do not support the 3 month implementation timeframe for Requirement 1. For many entities, it will take some time to develop a sound PSMP that meets the new PRC-005-2 standard. We suggest a 12 month implementation which we believe is more logical and in alignment with the implementation timeframe for Protection System Components with maximum allowable intervals of less than 1 year, as established in Table 1a. b. Although we support the implementation timeframes for Requirements R2, R3, and R4, we do not support the required periodic percentages of protections systems to be completed. There could be numerous reasons where an entity has to adjust its program schedule which could lead to noncompliance with these percentage milestones. We suggest simply requiring 100% completion of the maintenance per the maximum maintenance intervals. Alternatively an entity should have the flexibility to indicate they have fully transitioned to the new standard during the early stages of the implementation plan if their existing maintenance practices meet or exceed the standards minimum expectations. Doing so should negate the need to produce the "% complete" implementation status.
Individual
Jianmei Chai
Consumers Energy Company
No
1. If multiple redundant Protection System components, with associated parallel tripping paths, are provided, Table 1a, 1b, and 1c require that each parallel path be maintained, and that the maintenance be documented. Often, these multiple schemes are provided not to meet specific reliability-related requirements, but instead to provide operating flexibility. Testing these likely will require outages, and those outages may result in decreased reliability. Further, the documentation related to maintenance of all paths will be very cumbersome, and will lead to increased compliance exposure simply by its volume. This may perversely lead to entities NOT installing the redundant schemes, resulting in decreased reliability. 2. Many of the activities described in the Tables are not, by themselves, clear. The standard should include sufficient detail such that entities are clear as to what must be done for compliance, rather that relying on supplementary documents for this information. For example, it’s not clear, in Table 1a (Station DC Supply), what is meant by, “Verify that the dc supply can perform as designed when the ac power from the grid is not present.” Similarly, it isn’t clear from the general description within the Tables that components possessing different monitoring attributes within a single scheme, may be distinguished such that differing relevant tables can be used for the separate components. 3. In Table 1a, Station DC Supply, one of two optional activities is to “Verify that the station battery can perform as designed by evaluating the measured cell/unit internal ohmic values to station battery baseline. Battery assemblies supplied by some manufacturers have the connections made internally, making this option unavailable. Experience with ASME standards show that NERC and SDT members may be jointly and separately liable for litigation by specifying methods that either prefer or prohibit use of certain technologies. 4. Two of the four Maintenance Activities that begin with “Perform a complete functional trip …“ conclude with “… does not require actual tripping of circuit breakers or other interrupting devices. Do the other two such activities therefore require tripping of circuit breakers or other interrupting devices? 5. Performance of the minimum activities specified within Table 1a for legacy systems, particularly regarding control circuits, will require considerable disconnection and reconnection of portions of the circuits. Such activities will likely cause far more problems on restoration-to-service than they will locate and correct. We suggest that the SDT reconsider these activities with regard for this concern.
Yes
 
Yes
 
Yes
 
Yes
 
No
1. FAQ II.3A attempts to clarify the requirements of “Verify the proper functioning of the current and voltage signals necessary for Protection System operation from the voltage and current sensing devices to the protective relays” suggesting that “simplicity can be achieved” by verifying that the protective relays are receiving “expected values.” It concludes with a statement of the need to “ensure that all of the individual components are functioning properly …” implying that just verifying “expected values” at the protective relay end of the circuit may be inadequate. 2. FAQ II.4D describes what is required for testing of aux relays to include, “that their trip output(s) perform as expected”. Does that include timing tests? (Example – high speed ABB AR relays vs. standard AR relays). 3. The SDT responses to the Draft 1 comments regarding “grace periods” essentially says, “Absolutely not”. However, FAQ IV.1.D reflects data retention requirements relative to an entities’ program which includes a grace period!
1. In the Standard, Footnote 2 and Footnote 3 are identical. We presume that some information has been omitted. 2. We do not agree that Footnotes are an appropriate method of providing information that is important to the application of the Standard. Important information should be provided within the standard text.
Group
Santee Cooper
Terry L. Blackwell
SC Public Service Authority
No comment.
Yes
 
Yes
We are concerned with the long-term implementation of the data retention requirements for activities with long maximum intervals. For example, if you are performing an activity that is required every 12 years, the implementation plan says that you should be 100% compliant in 12 years following regulatory approval. However, assuming that 100% compliant meant that you got through all of your components once, you still would not be able to show the last two test dates. 12 years from now, would you still have to discuss the program you were using prior to 12 years ago for those components to have a complete audit, because of having to address the last 2 test dates?
No
In R1, a “Failure to specify whether a component is being addressed by time-based, condition-based, or performance-based maintenance” by itself is a documentation issue and not an equipment maintenance issue. Suggest this warrants only a lower VSL, especially when one of the required components can only be time based.
No Comment.
No comment.
There is some discussion in the documents, such as the definition of component in the Frequently-Asked Questions, about the idea that an entity has some latitude in determining the level of “protection system component” that they use to identify protection systems in their program and documentation. The example given is about DC control circuitry. There are requirements in this standard that are specific to a component, such as R1.1 – Identify all protection system components. Historically, if your maintenance and testing program is defined as (say, for relays) testing all the relays in a station at one time, your program, test dates, etc. could be identified by the station. There needs to be some addition, possibly to the Frequently asked questions, to explain what kind of documentation will be required with this new standard. For example, if your program is to test all the relays at a station every 4 years, and all the relays are tested at the same time, can your documentation of your schedule (the “date last tested” and previous date) be listed by station (accepting that you should have the backup data to show the testing was thorough) or must you be able to provide a list by each relay. Without some clarification, it seems like this could get confusing at an audit with many of the requirements pertaining to “each component.”
Individual
Art Buanno
ReliabilityFirst Corp.
Yes
The SDT has made significant and worthwhile changes to these tables. However, these tables still seem overly complex and should be simplified. One possibility would be to eliminate Table 1c and use Table 1b for those components that meet certain monitoring attributes. There are some errors in Table 1a in rows 5 and 6. In row 5 in the component column the word “contact” is missing. In the same row in the third column, there is an extra period. In row 6 in the third column, “circuit” should be “circuits” as in the other rows. The maintenance intervals seem to give preference to solid-state outputs but there is no evidence given that these are truly more reliable than an electromechanical trip at least not sufficient to double the maintenance interval.
No
R4 is the implementation of a maintenance program which is extremely important. Effective operation of the BES is so dependent on adequate maintenance that requirement R4 warrants a High VRF. It seems that requirement R3 may actually be better categorized as having an Operations Assessment Time Horizon as the entity needs to review events to analyze the adequacy of maintenance periods.
Yes
 
Yes
 
Yes
 
Yes
 
The SDT should be congratulated on its hard work in making substantial improvements to an existing standard. In revising the draft standard, the SDT should consider the difficulty an entity will have in providing the evidence required to show compliance. R1 unnecessarily limits PSMPs to “Protection Systems that use measurements of voltage, current, frequency and or phase angle to determine anomalies.” However, if an entity applies devices that protect equipment based on other non-electrical quantities or principles such as temperature or changes in pressure, the entity is not required to maintain them. These types of devices have long been considered by many organizations as important forms of protection and therefore in some instances are connected to trip. There are also many organizations that consider these types of devices too unreliable to use as protection and therefore only connect them for monitoring (and not to trip). If protection based on non-electrical quantities is not properly maintained, it will Misoperate and will negatively impact reliability. The standard cannot simply ignore a type of protection that can ultimately affect the reliability of the BES.
Group
PacifiCorp
Sandra Shaffer
PacifiCorp
Yes
 
Yes
Agree with the exception that the time horizon for implementation needs to recognize that documentation for maintenance tasks performed prior to this standard may not match current requirements and there should be no penalty for this.
No
Data retention requirements need to be modified. The need to maintain records of two previous tasks is excessive, one should be adequate. Per the two previous task requirements an entity may need to maintain records for 35 years.
Yes
 
Yes
 
Yes
 
R1.1: Please clarify what the requirements for “identify” means. Does each component need to be “identified” in our maintenance system, or at least referenced in the maintenance program or labeled in the field??? R4.3: Please provide guidance on what will be required to prove compliance that “maintenance correctable issues” have been identified and corrective actions initiated. What is the implication of finding maintenance correctable issues as it relates to other requirements for no single points of failure? In other words, if during maintenance a relay is found to have failed, is there an acceptable time period under which we may operate the system without redundancy until a repair can be made? Similarly, if part of a redundant relay system is taken out of service for maintenance, may the facility it was protecting be left in service? If not, then is the implication that protection systems must be triple redundant in order to do relay maintenance on in service equipment? Otherwise facilities would always have to be removed from service to do relay maintenance. Section D / 1.3: The data retention requirement for the two most recent performances of each maintenance activity is excessive. The requirement should be limited to the most recent or all activities since the last on-site audit. At the worse case an entity would have to retain records for up to 35 years for maintenance performed on a 12 year cycle. Table 1a “Protective Relay” entry: The last maintenance activity is listed as “for microprocessor relays verify acceptable measurement of power system input values ” for which a 6 year interval is provided”. How is this different than the next item “Voltage and Current Sensing Inputs to Protective Relays and associated circuitry” which is on a 12 year interval?? Please clarify this. Implementation Plan: This revised standard will drive significant revisions in existing maintenance programs. 3 months is not adequate time after approval to ensure compliance with R1. A minimum of 6 months should be utilized after regulatory approval. The Implementation plan requirements should also recognize that if the requirement to maintain records of the two previous maintenance tasks is implemented, it may not be possible to produce this information upon implementation. The implementation plan should be structured that the requirement to produce previous maintenance records should be phased in as the maintenance is performed. (ie. The requirement to produce two previous records for maintenance performed on a two year cycle should not be enforced until four years after implementation).
Individual
Tyge Legier
San Diego Gas & Electric
No
Proofing of CT circuits is not always trivial. Given this function is not presently being performed and documented by the company, a reasonable grace period would be required to achieve compliance. The company believes present practice, such as verification that relay current inputs are not zero and that phases are balanced, is a reasonable indication individual CTs are functioning properly. An entities protection system maintenance program is a Time Based Maintenance program. The protection system maintenance program describes the maintenance intervals and states that the protection system maintenance is triggered every 4 years. The maintenance program describes that the due date for compliance is 6 months past the trigger date to allow for planning and scheduling of the maintenance activity. Therefore the actual due date for the 4 year maintenance interval is 4 years and six months from the last maintenance completion date. The four year six month time based interval is within the six year maximum time based interval as required by PRC-005-2. Given the above, is the four year six month interval as described in the entities maintenance program compliant with PRC-005-2?
No
 
No
 
No
 
No
 
No
 
 
Group
Florida Municipal Power Agency
Frank Gaffney
Florida Municipal Power Agency
No
Will the Standard Introduce Technical Feasibility Exceptions to PRC Standards? A large proportion of the batteries (as high as 50% as reported by some SMEs) are not able to accommodate all of the tests prescribed in the draft standard. The phrase “Verify Battery cell-to-cell connection resistance” has entered the table where it did not exist before. On some types of stationary battery units, this internal connection is inaccessible. On other types the connections are accessible, but there is no way to repair them based on a bad reading. And bad cell-to-cell connections within units will be detected by the other required tests. This requirement will cause entities to scrap perfectly good batteries just so this test can be performed, with no corresponding increase in bulk electric system reliability while taking an unnecessary risk to personnel and the environment. And because buying battery units composed of multiple cells allows space saving designs, entities may be forced to buy smaller capacity batteries to fit existing spaces. This may end up having a negative effect on reliability. Suggest substituting “unit-to-unit” wherever “cell-to-cell” is used in the table now. The Standard Reaches Beyond the Statutory Scope of the Reliability Standards As written, the standard requires testing of batteries, DC control circuits, etc., of distribution level protection components associated with UFLS and UVLS. UFLS and UVLS are different than protection systems used to clear a fault from the BES. An uncleared fault on the BES can have an Adverse Reliability Impact and hence; the focus on making sure the fault is cleared is important and appropriate. However, a UFLs or UVLS event happens after the fault is cleared and is an inexact science of trying to automatically restore supply and demand balance (UFLS) or restore voltages (UVLS) to acceptable levels. If a few UFLS or UVLS relays fail to operate out of potentially thousands of relays with the same function, there is no significant impact to the function of UFLS or UVLS. Hence, there is no corresponding need to focus on every little aspect of the UFLS or UVLS systems. Therefore, the only component of UFLS or UVLS that ought to be focused on in the new PRF-005 standard is the UFLS or UVLS relay itself and not distribution class equipment such as batteries, DC control circuitry, etc., and these latter ought to be removed from the standard. In addition, most distribution circuit are radial without substation arrangements that would allow functional testing without putting customers out of service while the testing was underway, or at least without momentary outages while customers were switched from one circuit to another. Therefore, as written, we would be sacrificing customer service for a negligible impact on BES reliability.
No
R1, R2 and R3 are administrative in nature and ought to be a Low VRF, not a High or Medium VRF. R4 is doing the actual maintenance and testing and ought to be the highest VRF in the standard. Medium VRF is appropriate for R4.
Yes
M1 could be shortened to just a program in accordance with R1, rather than repeat the entire requirement
No
For the VSLs of R1 and R2, we do not understand where the 5%, 10% come from. There are only a few types of components, relays, batteries, current transformers and voltage transformers, DC control circuitry, communication, that’s 6 component types by our count, so, missing 1 component type in discussing the type of maintenance program is already a 17% error and Low, Medium and High VSLs are meaningless as currently drafted and every violation would be Severe, was the intention to apply this is a different fashion? Perfection is Not A Realistic Goal R4 allows no mistakes. Even the famous six sigma quality management program allows for defects and failures (i.e., six sigma is six standard deviations, which means that statistically, there are events that fall outside of six standard deviations). PRC-005 has been drafted such that any failure is a violation, e.g., 1 day late on a single relay test of tens of thousands of relays is a violation. That is not in alignment with worldwide accepted quality management practices (and also makes audits very painful because statistical, random sampling should be the mode of audit, not 100% review as is currently being done in many instances). FMPA suggests considering statistically based performance metrics as opposed to an unrealistic performance target that does not allow for any failure ever. Due to the shear volume of relays, with 100% performance required, if the standards remain this way, PRC-005 will likely be in the top ten most violated standards for the forever. In other words, 1-2% of components outside of the program should be allowed without a violation and Low VSL should start at a non-zero number, such as “Entity failed to complete scheduled program for 3-6% of components based on a statistically significant random sampling” or something to that affect. There is a fundamental flaw in thinking about reliability of the BES. We are really not trying to eliminate the risk of a widespread blackout, we are trying to reduce the risk of a widespread blackout. We plan and operate the system to single and credible double contingencies and to finite operating and planning reserves. To eliminate the risk, we would need to plan and operate to an infinite number of contingencies, and have an infinite reserve margin, which is infeasible. Therefore, by definition, there is a finite risk of a widespread blackout that we are trying to reduce, not eliminate, and, by definition, by planning and operating to single and credible double contingencies and finite operating and planning reserves, we are actually defining the level of risk from a statistical basis we are willing to take. With that in mind, it does not make sense to require 100% compliance to avoid a smaller risk (relays) when we are planning to a specified level of risk with more major risk factors (single and credible double contingencies and finite planning and operating reserves).
 
 
 
Individual
Greg Rowland
Duke Energy
No
General comment – the draft changes the word “verify” to “check” in several places; should use consistent phrasing throughout the standard. With regards to Table 1a, we have the following comments: • Control and trip circuits with electromechanical trip or auxiliary contacts (except for microprocessor relays. UVLS or UFLS) – We believe that while there may be value in a 6 calendar year cycle, this will be difficult to accomplish, since you either have to get outages scheduled or block protection, which risks reliability. Since this is essentially a re-commissioning check, the cycle should be 12 calendar years. Also 6 years appears to be in conflict with the system protection standard. • Control and trip circuits with unmonitored solid-state trip or auxiliary contacts (except for UVLS or UFLS) – agree with 12 calendar years as consistent with electromechanical above. • Control and trip circuits with electromechanical trip or auxiliary (UVLS or UFLS Systems Only) – 6 year cycle should be changed to 12 calendar years (see comment above on non-UVLS/UFLS). • Control and trip circuits with unmonitored solid-state trip or auxiliary contacts (UVLS or UFLS Systems Only) – agree with change to 12 calendar years. • Station dc Supply (used only for UVLS or UFLS) – Strike the word “Station”. We don’t differentiate between dc supply used for UFLS and other protection. • Station dc supply – Change 18 calendar months to 24 months, since this testing requires generator outages. Nuclear plant fuel cycles can be longer than 18 months. • Associated communications systems – More clarity is needed regarding what is to be included in the definition of “Associated”.
Yes
 
No
M4 states that entities shall have evidence such as maintenance records or maintenance summaries (including dates that the components were maintained). We would like to see M4 revised/expanded to explicitly include the FAQ Section IV 1.B information which states that forms of evidence that are acceptable include, but are not limited to: • Process documents or plans • Data (such as relay settings sheets, photos, SCADA, and test records) • Database screen shots that demonstrate compliance information • Diagrams, engineering prints, schematics, maintenance and testing records, etc. • Logs (operator, substation, and other types of log) • Inspection forms • U.S. or Canadian mail, memos, or email proving the required information was exchanged, coordinated, submitted or received • Database lists and records • Check-off forms (paper or electronic) • Any record that demonstrates that the maintenance activity was known and accounted for.
No
The VSLs for PRC-005-2 requirements R1, R2 and R4 have significantly tighter percentages than the corresponding requirements in PRC-005-1. We believe that the Lower VSL should be up to 10%, the Moderate VSL should be 10%-15%, the High VSL should be 15% to 20%, and the Severe VSL should be greater than 20%, which is still a lower percentage than the 25% Lower VSL currently in PRC-005-1.
Yes
 
Yes
 
 
Group
The Detroit Edison Company
Daniel Herring
NERC Compliance
No
Suggest that the interval for cell ohmic testing on VRLA batteries be changed to 12 months. Also, include ohmic testing of NiCad batteries at 18 mos as an option.
No
 
No
 
No
 
Yes
 
Yes
 
Suggest that the implementation plan for R1 (PSMP) be changed to 12 months. The statement in R1.1, “Identify all Protection System components” regarding the PSMP should be clarified. Is a complete list of every “component” of each specific protection system required to be included in the PSMP?
Group
Hydro One Networks
Sasa Maljukan
Hydro One Networks, Inc.
No
Table 1a: o V and I sensing to relays – 12 years? Why not perform this activity with mtce activities associated with relay mtce so that they line up? It would only be an incremental amount of work to perform this with associated relay maintenance work o Removal of requirement for testing of unmonitored breaker trip coils? Is it really the intention of the SDT to remove a requirement that would drive the industry to install TC monitors on breakers to improve reliability? o UFLS/UVLS DC control and trip circuits – Due to the distributed nature of this program, random failures to trip are not impactive to the overall operation of the UFLS protection. There should be no requirement to check the DC portion of these protections any more often than the DC circuit checks associated with that LV breaker. Since it is clear the requirement does not include the need to trip the breakers why the need to check the trip paths? Deletion of this requirement leaves the requirement to check only the relays and relay trip outputs from the protections every 6 years (or as often as the protective relay component type). o Along the same lines as the above comment should the maintenance activities for “UVLS and UFLS relays that comprise a protection scheme distributed over the power system” not be the same as “Protective Relays” Table 1c: o Level 3 attributes for “Associated communications systems” might better read “Evaluating the performance and quality of the channel as well as the performance of any interface to connected protective relays and alarming if the channel/protective relay connections do not meet performance criteria” o We believe that some of the proposed maintenance intervals for station DC supply are too stringent and that they would not produce significant increase in reliability to justify associated incremental expenditure. For example we suggest that the following changes are considered: - The interval for eelectrolyte level check for all batteries except VRLAs and internal measured cell/unit Ohmic value for VRLAs be extended to 6 months instead of current time period of 3 months. - The performance or service capacity test of the VRLA battery banks to be extended from 3 years to 5 years.
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
o Footnotes 2 and 3 on page 4 are identical. Delete footnote 3. o UFLS systems by design can suffer random failures to trip. It would make sense for a requirement to exist to perform maintenance on the UFLS relay as their failure to operate may affect numerous distribution level feeders. However maintenance on associated DC schemes connected to the devices should only be done on the same frequency as maintenance on the relevant interrupting devices. Consideration should be given to exempting schemes that have a maintenance program in place on those distribution level devices from PRC-005 Standard-specified maintenance intervals. Such Standard-specified intervals could apply to interrupting devices that have no maintenance program in place.
Group
PPL Supply
Annette M. Bannon
PPL Generation, LLC
No
PPL Generation, on behalf of the entities listed above, has the following comments on the dc entries in these tables: 1. Table 1a, Table 1b, Table 1c- Station DC supply - Maintenance Activities – references substation batteries. For generators, shouldn't that reference be station battery? Substation implies an association strictly with transmission, not generation. 2. Station DC supply - verify Battery continuity. What is the technical basis for this requirement? Neither battery installation and operation instructions nor technical reviews explain the basis for how this verification is supposed to work. NERC's Protection System Maintenance: A Technical Reference does not address this requirement. The Frequently-Asked Questions provides some ways that this verification can be completed. However, one example is tied to the microprocessor battery chargers. If there is a technical basis for this requirement, it should be provided. 3. Condition based monitoring on station dc supply - it appears the Table 1b excludes any condition based monitoring of the batteries because of the requirement for monitoring electrolyte level, individual cell state of charge, cell to cell and battery terminal resistance. Most monitoring equipment does not monitor those functions. 4. In general, the Tables are especially confusing in the dc system area. The “lines” overlap and need to be labeled, so they can be referenced in a maintenance document to show how the appropriate program can be followed. Each line should be separate in the function stated, so one can identify what has to be done to comply. 5. Provide examples of “non-battery-based dc equipment” that is covered under this standard. 6. For dc supply, the changes from the Sept. 2007 NERC “Protection System Maintenance”, A Technical Reference seem too restrictive. The Sept. 2007 document contained a solid maintenance program. What is the basis for the change?
No comment.
No
Measurers M1 – requires having a maintenance program that addresses control circuitry associated with protective functions from the station dc supply through the trip coil(s) of the circuit breakers. Some generators do not own this equipment to the circuit breaker or other interrupting devices. The requirement should be to maintain and test the equipment owned by the generator. Data Retention 1.3 references on-site audits. Entities registered as GO and GOP are not audited on-site.
No Comment.
No Comment.
No Comment.
1. For applicability to generators, the responsibility for a maintenance program will usually rest with the plant operator when the operator and plant owner(s) are different entities. Consider changing the applicability as it applies to the generator in such situations. 2. Time-based frequency should allow for flexibility; i.e. engineering analysis should allow the entity to exceed the intervals noted in the table. An engineering evaluation that defines a test interval differently than those intervals prescribed in the table should allow an entity to build a program with different intervals. 3. A Grace Period should be defined. This allows a tolerance window to allow for unforeseen occurrences. A grace period would allow for some schedule flexibility and reduce the number of reports to the regulator for exceeding an interval by a reasonable about. 4. The implementation plan for this revision should take into account that a generator outage may be required to implement a new maintenance frequency. The implementation plan should account for outage time, especially nuclear plants that have extended operating cycles. 5. Table 1b Protective Relays Level 2 Monitoring Attributes includes input voltage or current waveform sampling three or more times per power cycle. No further guidance is provided in the reference documents. If this sampling rate is not provided in the specification by the manufacturer, what can the entity use to demonstrate that the attribute is satisfied? Please provide additional guidance. 6. Consider numbering the tables to improve cross-referencing the entries in program documentation. This will allow entities to reference in program documents exactly which activities are being implemented in accordance with the standard. 7. Requirement 1.1 states, “Identify all Protection System components.” This is too broad and must be clarified.
Individual
Claudiu Cadar
GDS Associates
No
- Table 1a. Protective relays oFor microprocessor relays need guidance in how all the inputs/outputs will be checked and how is determined which one are “essential to proper functioning of the Protection System” oFor microprocessor relays need guidance in how the acceptable measurement is physically determined. - Table 1a. Voltage and current sensing inputs to Protective Relays and associated circuitry oHow verify the proper functioning? By ratio test comparison? - Table 1a. Control and trip circuits with electromechanical trip or auxiliary contacts (except for microprocessor relays, UFLS or UVLS) oThis can be dangerous if backup protection or breaker failure protection schemes not disabled at the time of the functional trip test - Table 1a. Control and trip circuits with electromechanical trip or auxiliary (UFLS/UVLS systems only) oMissing the word “contacts” in the naming of the type of PS component oIf distribution circuit has no breaker bypass will require a tremendous amount of switching or customer outages. - Table1a. Station dc supply (that has as a component Vented Lead-Acid batteries) oWhy is this 18 months when Regulated batteries are required to be verified every 3 months? - Table1a. UVLS and UFLS relays that comprise a protection scheme distributed over the power system oNeed to define this type of UVLS and UFLS relays
 
 
No
- We do agree with the majority of the assignments that have been made, however the standard needs specific guidance so to be clearly evidentiated the components as included in the definition of Protection System. The applicability of the standard does not address the current issues regarding radial + load serving only situation when Protection System not designed to provide protection for the BES. - Not sure if the percentages corresponding to the events and activities are appropriately assigned. What were the criteria on which all these percentages are based upon? - Requirement R3 Severe VSL note 3 allows smaller segment population than the Lower VSL. How these segment limits were developed?
 
 
- Definition of Terms Used in the Standard. Protection System Maintenance Program oMonitoring. Concerned about the interpretation of this activity description oUpkeep. Not sure about how this activity will be enforced - A. Introduction. 4.2. Facilities. oThe applicability does not address the current issues regarding radial + load serving only situation when Protection System not designed to provide protection for the BES. Standard should clearly state this exemption. - B. Requirements. o1.1. The standard does not provide guidance in how to identify the components of a transmission Protection System (tPS). See prior comment referring to the case of a radial load serving transmission topology. o1.3. Requirement should read “For each identified Protection System component from Requirement 1, part 1.1, include all maintenance activities listed in PSMP and specified in Tables 1a, 1b, or 1c associated with the maintenance method used per Requirement 1, part 1.2.” o1.4. This requirement should be eliminated since already included in Table 1a and covered through Requirement 1, part 1.3. o4.3. Footnote 3 shall be eliminated since duplicates footnote 2 - C. Measures oM1. The added wording in the Protection System definition, requirements and measures with respect to the inclusion of the “associated circuitry from the voltage and current sensing devices” and control circuitry “through the trip coil(s) of the circuit breakers or other interrupting devices” seem right but a bit excessive under current circumstances (form of the standard). The standard should clearly specify how the maintenance program will address the verification, monitoring, etc. of the actual wiring and the trip coils. We suggest that the wording of the standard to reflect that the maintenance activities on the wiring will be conducted in a visual fashion without implying activities that require disconnecting the primary equipment. We recommend to change the Protection System definition to read “up to the trip coils(s)” instead the word “through” (see comment on the definition as well). We consider that the gain in reliability by pursuing a thorough maintenance program that require to take primary equipment out of service (which in many instances will lead to the entire substation being put out of service) cannot counterweight the sole purpose of the standard and the economics emerging from this program.
Individual
Kirit Shah
ameren
No
Ameren does agree that draft 2 is a considerable improvement from draft 1 of PRC-005-2; however the following still need to be addressed. 1) Use “Control circuitry” to be consistent with the proposed definition. If ‘and trip’ was included so that users would know this is a trip circuit, then the definition should use ‘Trip circuitry’ instead of ‘Control circuitry’. It is important to use consistent terminology throughout the definition and the standard. 2) Please add row numbers in each of Tables 1a, 1b, and 1c, and arrange so that row 1 in each table corresponds, etc. (or state which rows correspond to each other.) This would help clarify movement from table to table. The number of sub clauses, nuances, and varied Type of Component descriptors among rows in the same table as well as from table-to-table can be overwhelming. This would help keep Regional Entities and System Owners from making errors. 3) Please clarify that the instrument transformer itself is excluded. The standard indicates that only voltage and current signals need to be verified. The FAQ seems to cover this, but see our comments on your question 6. 4) Clarifications need to be made on testing requirements on trip contacts relative to microprocessor vs. EM relays. Digital relays have electromagnetic output relays. Do they fall into the electromechanical trip or solid state trip? 5) There appears to be an inconsistency in the use of “check” vs. “verify” in the tables. Consider modifying the definition of “verification” to “A means of determining or checking that the component is functioning properly or that the maintenance correctable issues are identified”, eliminate use of the term “verify proper functioning” (which seems to be redundant by PRC-005-2 standard definition), and simply use the term “verify”. 6) Alternately if the term “check” replaced “verify proper functioning” in order to allow for the completion of a maintenance activity within the required interval and yet account for an outstanding maintenance correctable issue being present, suggest the other remaining activities in the tables where the term “verify proper functioning” is used, also be replaced with “check”. 7) If there is an intentional difference between “verify” and “check”, shouldn’t “check” be defined if it is to be included as a PSMP activity term? 8) Functional trip testing will require extensive analysis and could involve an extensive testing evolution to ensure the correct circuit is tested without unexpected trip of other components, particularly for generator protection systems and some transmission configurations. The complexity of the system and the test would be conducive to an error that resulted in excessive tripping, thus affecting the reliability of the BES. It would seem that the potential for an adverse affect from this test would be greater than the benefit gained of testing the circuit. In addition, scheduling outages to perform the functional trip testing in conjunction with other outages required to perform maintenance and other construction activities will be difficult due to the large number of outage requirements for the functional testing. This will challenge the BES more often and thus reduce reliability. For these reasons functional trip testing is too frequent, and should be extended to twelve years. 9) In battery maintenance table, we suggest that “cell/unit” be changed to “cell or unit.” Suggest substituting “unit-to-unit” wherever “cell-to-cell” is used in the table now. Many batteries are packaged such that the individual cells are not accessible. 10) IEEE battery maintenance standards call for quarterly inspections. These are targets, though, not maximums. An entity wishing to avoid non-compliance for an interval that might extend past three calendar months due to storms and outages must set a target interval of two months thereby increasing the number of inspections each year by half again. This is unnecessarily frequent. We suggest changing the maximum interval for battery inspections to 4 calendar months. For consistency, we also suggest that all intervals expressed as 3 calendar months be changed to 4 calendar months. 11) Replace “State of charge of the individual battery cells/units” with “Voltage of the individual battery cells or units”. 12) The maximum maintenance interval for a lead-acid vented battery is listed at 6 calendar years for performing a capacity test. This type of test has been proven to reduce battery life and an interval of 10 to 12 years would be better. 13) The level 2 table regarding Protection Station dc supply states that level 1 maintenance activities are to be used, but then goes on to give a list of Maintenance Activities that don’t match those in level 1. Which activities shall we use? Same situation for Station DC Supply (battery is not used) where the 18 month interval is missing. 14) Also, Table 1B, in the second to last row, should be referring to UFLS rather than SPS.
No
The VRF for R1 should be Medium because the failure to do so is commensurate with the risks of the other requirements. For example, failing to establish a PSMP for some portion of the entity’s components could lead to their maintenance not meeting this standard; this is the same is establishing the PSMP and then not performing the maintenance per the standard.
No
1) M2 incorrectly excludes Distribution Provider. 2) For those components with numerous cycles between on-site audits, retaining and providing evidence of the two most recent distinct maintenance performances and the date of the others should be sufficient. If an entity misses a required maintenance, that results in a self report. We are subject to spot audits and inquiries at any time between on-site audits as well. 3) For those components with cycles exceeding on-site audit interval, retaining and providing evidence of the most recent distinct maintenance performance and the date of the preceding one should be sufficient. Auditors will have reviewed the preceding maintenance record. Retaining these additional records consumes resources with no reliability gain. 4) FAQ II 2B final sentence states that documentation for replaced equipment must be retained to prove the interval of its maintenance. We oppose this because: the replaced equipment is gone and has no impact on BES reliability; and such retention clutters the data base and could cause confusion. For example, it could result in saving lead acid battery load test data beyond the life of its replacement.
No
1) The Lower VSL for all Requirements should begin above 1% of the components. For example for R4: “Entity has failed to complete scheduled program on 1% to 5% of total Protection System components.” PRC-005-2 unrealistically mandates perfection without providing technical justification. A basic premise of engineering is to allow for reasonable tolerances, even Six Sigma allows for defects. Requiring perfection may well harm reliability in that valuable resources will be distracted from other duties. 2) In R1, a “Failure to specify whether a component is being addressed by time-based, condition-based, or performance-based maintenance” by itself is a documentation issue and not an equipment maintenance issue. Suggest this warrants only a lower VSL, especially when one of the required components can only be time based. 3) It is possible that a component that failed to be individually identified per R1.1 was included by entity A’s maintenance plan. This documentation issue gets a higher VSL than entity B that identified a component without maintaining it. We suggest the R1 VSL be change to Low, since we believe lack of maintenance to be more severe than documentation issues.
No
1) Is this document considered part of the standard? We expect to use it as a reference in developing our PSMP, during audits, and for self-certification as an authentic source of information. It is also unclear how this document will be controlled (i.e. Revised and Approved, if at all). 2) On page 22 please clarify that only applies to high speed ground switches associated with BES elements. 3) We appreciate the SDT providing this valuable reference.
Yes
1) Is this document considered part of the standard? We expect to use it as a reference in developing our PSMP, during audits, and for self-certification as an authentic source of information. It is also unclear how this document will be controlled (i.e. Revised and Approved, if at all). 2) The FAQ needs to be aligned with the tables. The FAQ also contains a duplicate decision tree chart for DC Supply. The FAQ contains a note on the Decision tree that reads, "Note: Physical inspection of the battery is required regardless of level of monitoring used", this statement should be placed on the table itself, and should include the word quarterly to define the inspection period. 3) We appreciate the SDT providing this valuable reference.
1) We commend the SDT for developing a generally clear and well documented second draft. The SDT considered and adopted many industry comments from the first draft. It generally provides a well reasoned and balanced view of Protection System Maintenance, and good justification for its maximum intervals. Ameren generally agrees that this second draft will be beneficial to BES reliability, but several inconsistencies, unclear items, and a couple issues need to be addressed before we will be able to support it. 2) Facilities Section 4.2.1 “or designed to provide protection for the BES” needs to be clarified so that it incorporates the latest Project 2009-17 interpretation. The industry has deliberated and reached a conclusion that provides a meaningful and appropriate border for the transmission Protection System; this needs to be acknowledged in PRC-005-2 and carried forward. 3) We are concerned over R1.1, where all components must be identified, without a definition for the word component or the granularity specified. While the FAQ gives a definition, and allows for entity latitude in determining the granularity, the FAQ is not part of the standard. Certainly this could confuse an entity or an auditor and lead to much wasted work and / or violations for unintended or insignificant issues. We suggest that the FAQ definitions be included within the standard. 4) Implementation of the PSMP must coincide with the beginning of a calendar year. 5) Generating Plant system-connected Station Service transformers should not be included as a Facility because they are serving load. Omit 4.2.5.5 from the standard. There is no difference between a station service transformer and a transformer serving load on the distribution system. This has no impact on the BES, which is defined as the system greater than 100 kV. 6) The term “maintenance correctable issue” used in Requirement 4 seems to be at odds with the definition given for it. It seems that an issue that cannot be resolved by repair or calibration during the maintenance activity would be a maintenance non-correctable issue. Also, in Requirement 4, the term “identification of the resolution” is ambiguous. Suggested changes for Requirements 4 and 4.1 are: “R4. Each Transmission Owner, Generator Owner, and Distribution Provider shall implement its PSMP, and resolve any performance problems as follows: 4.3 Ensure either that the components are within acceptable parameters at the conclusion of the maintenance activities or initiate actions to replace the component or restore its performance to within acceptable parameters.”
Individual
Joe Knight
Great River Energy
No
In Table 1a section-Station DC Supply – 18 calendar months, under Maintenance Activities column, suggest changing under Verify: Battery terminal connection resistance To: Entire battery bank terminal connection resistance (This could have been interpreted as individual batteries) And change: Battery cell-to-cell connection resistance To: Battery cell-to-cell connection resistance, where an external mechanical connection is available. In Table 1a-Station dc supply (that has a component Valve Regulated Lead-Acid batteries) suggest changing Max Maintenance Interval=3 Calendar Years or 3 Calendar Months to 4 Calendar Years or 12 Calendar Months. Our concern is that the insurance companies may push NERC maintenance intervals on all battery banks not associated with the BES. Table 1a-Station dc supply (that has as a component Lead-Acid batteries) Max Maintenance Interval=6 Calendar Years suggest changing to 10 Calendar Years. Reason: performance tests may degrade the battery. Table 1a-Station dc supply (that has as a component Nickel-Cadmium batteries) Max Maintenance Interval=6 Calendar Years suggest changing to 10 Calendar Years. Reason: performance tests may degrade the battery. Table 1b -Level 2 Monitoring Attributes for Component in the row labeled (Control and trip circuitry) we suggest the following change: If a trip circuit comprises multiple paths, at least one of those paths is monitored. Alarming for loss of continuity or dc supply for trip circuits is reported to a location where action can be taken. While all tripping circuits are not completely monitored, the trip coils and the outdoor cable runs are completely monitored. The only portion that would not be monitored is a portion of inter and intra-panel wiring having no moving parts located in a control house. Our company has extremely low failure rate of panel wiring and terminal lugging. I don’t think that there is provision for moving control and trip circuitry to performance based maintenance? This control circuitry should be maintained less frequent than un-monitored trip circuits (6 years).
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
 
Individual
Terry Bowman
Progress Energy Carolinas
No
• The modified definition of “Protection System” (page 2 of the clean version of PRC-005-2) uses the terminology “control circuitry associated with protective functions” whereas Table 1a rows 3-6, Table 1b Rows 3 and 5, and Table 1c Row 4 uses the terminology “control and trip circuits.” This is a conflict. “Control” implies that the standard applies to closing/reclosing circuits as well. We do not believe that is the intent. • Row 7 of Table 1a (page 10 of the clean version of PRC-005-2) indicates that proper voltage of the station dc supply must be verified when the associated UVLS or UFLS maintenance is performed. It is not clear whether this requirement is over and above the quarterly and 18-month battery maintenance listed elsewhere in the table or is it the only battery maintenance required for UVLS and UFLS systems? If the intent is to check the station dc supply only when UVLS and UFLS maintenance is performed, the other rows addressing station dc should be revised to exclude UVLS and UFLS. • Row 4 of Table 1b (page 14 of the clean version of PRC-005-2) indicates that remote alarms must be verified every twelve calendar years for control circuitry (trip circuits) (except UFLS/UVLS) provided “Monitoring of Protection System component inputs, outputs, and connections” exists. Clarification should be made to indicate how to monitor inputs. For example, a breaker auxiliary switch is relied upon to communicate breaker status to a protective relay. If the switch is out of adjustment so that incorrect breaker status is reported to the relay, the relay may not operate when needed. Could proper operation of the auxiliary contacts be credited through in-service operation or the six-year breaker operation maintenance? • The term “calendar years” is used to define the maximum intervals. Does this mean that a six-year PM could go one-day shy of seven years? For example, if a six-year maintenance PM was last performed on 1/1/2010, it would be due on 1/1/2016. Could this allow until 12/31/2016 to complete the maintenance? • Table 1b, Row 14 (Row 2 on page 17): Under the “Level 2 Monitoring Attributes for Component,” UFLS/UVLS should be referenced instead of SPS. • Clarifications need to be made on testing requirements on trip contacts relative to microprocessor vs. EM relays. • There appears to be an inconsistency in the use of “check” vs. “verify” in the tables. • In battery maintenance table, we suggest that “cell/unit” be changed to “cell or unit.”
Yes
 
No
M2 incorrectly excludes Distribution Provider.
No
In the VSL for R1, a failure to “specify whether a component is being addressed by time-based, condition-based, or performance-based maintenance” by itself is a documentation issue and not an equipment maintenance issue. Suggest this warrants only a lower VSL, especially when one of the required components can only be time based.
Yes
 
No
FAQ II.2.A: What degree of testing is required for a relay firmware upgrade? Complete commissioning tests? FAQ V.1.A. There appears to be a typo in Example #1 for “Vented lead-acid battery with low voltage alarm connected to SCADA (level 2)”: Table 1b does not list any level 2 requirements. Rather, the table refers reader back to the Level 1 requirements. Same comment for Example #2 as well. FAQ III.1.A: Project 2009-17 provides a response to a request for interpretation of the term “transmission Protection System” as related to PRC-004-1 and PRC-005-1. The interpretation addresses the boundaries of the transmission system. NERC should investigate whether this same boundary should be defined within the new PRC-005-2. Also, numerous potential boundary issues exist between entities which should be contemplated and addressed. See the examples below: • Utility A may own equipment in Utility B’s substation. Utility A contracts Utility B to perform maintenance on their equipment. However, the two utilities have different maintenance programs and intervals for the same types of equipment. Who is responsible for NERC compliance? Would Utility A be found in violation because their equipment is being maintained under Utility B’s program which deviates from Utility A’s maintenance basis? • EMC protection is fed from a utility’s instrument transformers. Who is responsible for validation of the relay inputs and testing of the instrument transformers? • Utility-owned communication units (used for transfer trip or carrier blocking) are coupled to the utility’s power line using customer-owned CCVTs. Who is responsible for maintenance and testing of these CCVTs? • Utility A owns all equipment at one end of line (line terminal A) and Utility B owns all equipment at other end of line (line terminal B). Who is responsible for demonstrating the carrier blocking scheme or POTT scheme works correctly?
• R1.1.1 states that “all” protection system components be identified. Does the term “all” refer to the major components identified in the Protection System definition (protective relays, communication systems, voltage and current sensing devices, station dc supply, and control circuitry) or does it include all sub-components (jumpers, fuses, and auxiliary relays used in dc control circuits and communication paths/wavetraps/tuners/filters)? We assume the former but request clarification. • Draft Implementation Plan for PRC-005-02: The phased implementation plan for R2, R3, and R4 seems reasonable. However, the three-month implementation plan for R1 seems extremely short. Utilities will have to change procedures, job plans, basis documents, provide training, and change intervals in their work tracking databases. In addition, if the utility wants to take advantage of the longer intervals allowed by partial monitoring, significant print work must be performed up front. • Descriptors in the type of the protection system column needs to be consistent between 1A, 1B and 1C. In the tables, please clarify “complete functional trip test” for UVLS and UVLS trip tests since the breaker is not being tripped.
Group
Pepco Holdings, Inc. - Affiliates
Richard Kafka
Pepco Holdings, Inc.
There were numerous comments submitted for Draft 1 indicating that the 3 month interval for verifying unmonitored communication systems was much too short. The SDT declined to change the interval and in their response stated: The 3 month intervals are for unmonitored equipment and are based on experience of the relaying industry represented by the SDT, the SPCTF and review of IEEE PSRC work. Relay communications using power line carrier or leased audio tone circuits are prone to channel failures and are proven to be less reliable than protective relays. Statistics on the causes of BES protective system misoperations, however, do not support this assertion. The PJM Relay Subcommittee has been tracking 230kV and above protective system misoperations on the PJM system for many years. For the six year period from 2002 to 2007, the number of protective system misoperations due to communication system problems were lower (and in many cases significantly lower) than those caused by defective relays, in every year but one. Similarly, RFC has conducted an analysis of BES protection system misoperations for 2008 and 2009, and found the number of misoperations caused by communication system problems to be in line with the number attributed to relay related problems. If unmonitored protective relays have a 6 year maximum maintenance/inspection interval, it does not seem reasonable to require the associated communication system to be inspected 24 times more frequently, particularly when relay failures are statistically more likely to cause protective system misoperations. As such, a 12 or 18 calendar month interval for inspection of unmonitored communication systems would seem to be more appropriate. FAQ II 6 B states that the concept should be that the entity verify that the communication equipment...is operable through a cursory inspection and site visit. However, unlike FSK schemes where channel integrity can easily be verified by the presence of a guard signal, ON-OFF carrier schemes would require a check-back or loop-back test be initiated to verify channel integrity. If the carrier set was not equipped with this feature, verification would require personnel to be dispatched to each terminal to perform these manual checks. The phrase “Verify Battery cell-to-cell connection resistance” has entered the table where it did not exist before. On some types of stationary battery units, this internal connection is inaccessible. On other types the connections are accessible, but there is no way to repair them based on a bad reading. And bad cell-to-cell connections within units will be detected by the other required tests. This requirement will cause entities to scrap perfectly good batteries just so this test can be performed, with no corresponding increase in bulk electric system reliability while taking an unnecessary risk to personnel and the environment.
No
An explanation is needed to justify why the VRF for R1 of the PSMP is High whereas the implementing and following of the PSMP is Medium, R2, R3 & R4.
No
The present wording regarding data retention states - The Transmission Owner, Generator Owner, and Distribution Provider shall each retain documentation of the two most recent performances of each distinct maintenance activity for the Protection System components, or to the previous on-site audit date, whichever is longer. This wording was changed by the SDT following comments received from Draft 1. However, the present wording is somewhat confusing. It is assumed that the intent of the SDT was to require documentation be retained for the two most recent performances of each distinct maintenance activity, regardless of when they occurred (i.e., whether prior to, or since the last audit), since the phrase whichever is longer was used. In addition, for those activities requiring short maintenance intervals (such as battery inspections), records must be kept for all performances (not just the last two) that have taken place since the last on-site audit. For example: Assume a PSMP with a 6 year interval for relay maintenance and 3 month interval for battery inspections. At a particular station assume the batteries have been inspected every 3 months; the relays were last inspected 5 years ago, and before that 11 years ago. The last audit was 2 years ago. Records from each 3 month battery inspection going back to the last audit needs to be retained. Also, both relay maintenance records from 5 and 11 years ago needs to be retained, despite the fact that this interval should have been reviewed during the last audit. Documentation from the 11 year ago activity can be discarded when the relays are next maintained. Is this what the SDT intended? If so, the requirement should be re-worded to better explain the intent. Also, examples should be included in either the FAQ or Supplemental Reference to demonstrate what is expected.
No
It is possible that a component that failed to be individually identified per R1.1 was included by entity A’s maintenance plan. This documentation issue gets a higher VSL than entity B that identified a component without maintaining it. We suggest the R1 VSL be change to Low, since we believe lack of maintenance to be more severe than documentation issues.
No
Figure 1 & 2 Legend (page 29), Row 5, Associated Communications Systems, includes Tele-protection equipment used to convey remote tripping action to a local trip coil or blocking signal to the trip logic (if applicable). This description does not include all the various types of signals communicated for proper operation of various protective schemes (i.e., DUTT, POTT, DCB, Current Differential, Phase Comparison, synchro-phasors, etc.) A more inclusive and generic description might be – Tele-protection equipment used to convey specific information, in the form of analog or digital signals, necessary for the correct operation of protective functions. This is also consistent with the revised definition of Protection System. Conversely, excluded equipment would be - Any communications equipment that is not used to convey information necessary for the correct operation of protective functions.
No
The three month inspection interval for communication equipment mentioned in FAQ II 6 B should be extended to 12 – 18 months (see response to Question #1). In addition, the example used in this section should address what is expected for ON-OFF carrier systems. Checking that the equipment is free from alarms and still powered up does not seem sufficient to verify functionality. The FAQ states that the concept should be that the entity verify that the communication equipment...is operable through a cursory inspection and site visit. However, unlike FSK schemes where channel integrity can easily be verified by the presence of a guard signal, ON-OFF carrier schemes would require a check-back or loop-back test be initiated to verify channel integrity. If the carrier set was not equipped with this feature, verification would require personnel to be dispatched to each terminal to perform these manual checks.
Dates of the Supplemental Reference Documents in Section F of the standard need to be updated. The word “calendar” is used widely to define month and year intervals. Sometimes causes confusion, need definition/examples. The level 2 table regarding Protection Station dc supply states that level 1 maintenance activities are to be used, but then goes on to give a list of Maintenance Activities that don’t match those in level 1. Which activities shall we use? Same situation for Station DC Supply (battery is not used) where the 18 month interval is missing. Req 1.1: “All Components” wording should say something like all components covered in our plan
Individual
Martin Bauer
US Bureau of Reclamation
No
There is no reliability based justification to alter the standards to include allowable intervals. The intervals prescription for performance based PSMP virtually eliminates the capability of smaller utilities who do not have a large equipment database to justify a performance based system that may be sound based on their experience. This overly prescriptive approach should be eliminated and return to allowing utilities to justify their programs. The standard should return to addressing real reliability impacts as required by law. This would be to develop a maintenance required which identifies that if it is shown that an event in which reliability is impacted by the utilities PSMP, as evidenced by disturbance reports, the utility would be required to submit to the RRO a corrective action plan which addresses how the PSMP will be revised and when compliance with that PSMP is to be achieved. Finally, the standard presumes that components within a BES Element will cause a reliability impact to the BES. In numerous meeting with NERC and WECC it was emphasized that a reliability impact has been described as causing cascading outages or causing loss of service to load above a certain magnitude. The BES has an ability to absorb element outages resulting from a variety of causes without impact load or resulting in cascading outages.
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 maintenance programs. The internal processes associated with these vary based on the size of the utility. 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 requirements and 18 months to train the staff and implement the new program.
No
The measures M2, M3, and M4 are redundant to measure M1. Either eliminate M1 or M2 through M4. The entity must provide documentation of its maintenance program in M1 irrespective of the type used. As previsously mentioned there is not reliability based justification for the documentation required. The Entity should be afforded the freedom to make intelligent maintenance choices based on inumberable factors. These choices will be reviewed if a reliability impact is determined to be related to the choices.
No
The VSL's use terms that are not tied back to a requirement and appear to be based on the concept that every component will cause an impact on the BES. The VSL's use the term "coutable event" to score the VSL; hoever, there is no requirement associated with the number of "countable events". The VSL's should allow for minor gaps in maintennace documentation where there is no impact to the BES if the component failed.
No
It is not reasonable to assert that a statistical analysis of survey data is a reliability based justification for requiring specific maintenance intervals. The reference document admits that intervals varied widely. To assert a postage stamp interval does not account for other variables which optimize a specific maintenance program. That is not say that the reference documents is worthless. Indeed it has many good suggestions. However, to impugn the maintenance programs in practice because they do not follow the "weighted average" is hardly scientific or credible. The reference document should analyze the maintenance programs from the stand point of the outages associated with those facilities. If a specific maintenance practice was shown to have compromised the performance of the facility and the reliability of the BES, then it would added to the statistical database of practices which would not be acceptable. Now the statistical analysis of the database would show that certain practices have consequences which impact reliability and a requirement can be constructed to disallow them.
 
The sub-requirements for R1, are not criteria, rather implementation requirements more suitable to be included in R4. Examples of what the PSMP shall address which would be more consistent with the language in R1 would be: How are changes to the PSMP administered? Who approves the determination of the use of time-based, condition based or performance based maintenance. Who reviews activities under the PSMP References used within the standard are not consistent. In R1.2 Attachment as is referred to as Attachment A. In R3 Attachment A is referred to as PRC-005 Attachment A. This implies a difference. Under a voluntary world, we could draft criteria and procedures with this problems and interpret them correctly. Today in the compliance world, the language must be precise and unambiguous. The reference must be the same it means something different. The requirement in R1, which is consistent with the purpose, does not support the applicability in R4.2.5.4. Protection systems associated with stations service are not designed to provide protection for the BES. In particular we have been told that intent was not to look at every device that tripped the generator but devises that sensed problems on the BES and trip the generator. Hence we include such things as frequency relays, Differential relays, zone relays, over current, and under voltage relays. Even a loss of field looks at the system as included. Speed sensing devices were explicitly excluded. As such, if the stations service transformer protection looks toward the BES (e.g. differential relays and zone relays) they would be included. Over current would not as it would be on the station side. If a Station Service transformer saw excess current, the system would in most cases fail over to other side. If not, it would cause the generator to trip much like a generator thermal device which is also excluded. Maintenance programs offer a unique problem to the FERC and regulatory world. The knee jerk reaction is to define them. What happens if the solution is bad, who will accept the consequences that narrow prescription was wrong and the interval caused a reliability impact. It would no longer be the Entity. History is replete with examples of this type of micro managing. Rather than fall into the same trap, and suffer the consequences of the unknown, allow Entities to optimize their programs to ensure reliability of the BES and create a standard of disallowed practices which have a demonstrated impact on reliability.
Group
NERC Staff
Mallory Huggins
NERC
Yes
 
 
Yes
Make sure that the use of verbs like “shall,” “should,” and “will” is consistent across Requirements and Measures. In these four measures, all three verbs are used, and they should be made uniform to avoid misinterpretation.
 
Yes
 
Yes
 
NERC staff is pleased with the current iteration of this standard. The staff understands that while PRC-005-2 has historically been the most frequently violated standard, it has mostly been due to documentation issues. The standard has not been much of a heavy hitter in causal or contributive aspects, and with respect to relay operations, there have been very few times that lack of maintenance has been the problem. NERC staff does propose a slight change to 4.2.5.1. The concern is that 4.2.5.1 could be interpreted to apply to devices that protect the generator as opposed to those that protect the Bulk Electric System. The suggested language is as follows: “Protection System components that act to trip generators that are part of the BES, either directly or via generator lockout or auxiliary tripping relays.” Additionally, staff suggests some changes to R1. In that requirement, the PSMP covers “Protection Systems that use measurements of voltage, current, frequency and/or phase angle to determine anomalies and to trip a portion of the BES…” It probably would be better if the list was limited to voltage and current or if the list was replaced with electrical quantities. The former would be okay since voltage and current are the only two electrical quantities that relays measure directly. To remove ambiguity, the most inclusive way to rephrase this is probably the latter alternative, to change the requirement to, “…that use measurements of electrical quantities to determine anomalies…” Finally, Footnotes 2 and 3 (in Requirement 4) are identical. Unless that’s intentional, one should be removed. (And note that Footnote 2 is missing a period.)