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Individual or group.  (41 Responses)
Name  (25 Responses)
Organization  (25 Responses)
Group Name  (16 Responses)
Lead Contact  (16 Responses)
Contact Organization  (16 Responses)
Question 1  (37 Responses)
Question 1 Comments  (41 Responses)
Question 2  (36 Responses)
Question 2 Comments  (41 Responses)
Question 3  (36 Responses)
Question 3 Comments  (41 Responses)
Question 4  (39 Responses)
Question 4 Comments  (41 Responses)
Question 5  (23 Responses)
Question 5 Comments  (41 Responses)
Question 6  (34 Responses)
Question 6 Comments  (41 Responses)
Question 7  (33 Responses)
Question 7 Comments  (41 Responses)
Question 8  (38 Responses)
Question 8 Comments  (41 Responses)
Question 9  (37 Responses)
Question 9 Comments  (41 Responses)
Question 10  (36 Responses)
Question 10 Comments  (41 Responses)
Question 11  (35 Responses)
Question 11 Comments  (41 Responses)
Question 12  (36 Responses)
Question 12 Comments  (41 Responses)
Question 13  (34 Responses)
Question 13 Comments  (41 Responses)
Question 14  (31 Responses)
Question 14 Comments  (41 Responses)
 
Group
Northeast Power Coordinating Council
Guy Zito
Northeast Power Coordinating Council
No
The VRF for R1 for the development and documentation of UFLS program criteria is stated as a Low VRF. Such a requirement to develop overall UFLS program criteria was more than a ‘Low’ or Administrative requirement, and the VRF for this requirement should be listed as a Medium VRF. The requirement to develop program criteria in Requirement R1 is as important as those requirements stated in Requirement R2 which was assigned a Medium VRF by the DT.
Yes
The Measures are logical and consistent with the corresponding requirements.
Yes
 
Yes
 
 
Yes
 
Yes
EOP 003 is on the list of standards identified by the NERC Tiger Team for fast tracking of Order 693 directives. There is concern that coordination between these two DT’s may not have occurred and that the changes agreed upon in the revised UFLS SAR should also be considered by the Tiger Team.
No
Significant amounts of UFLS capability may fall outside the current FM design, and the DT is trying to capture all entities that control UFLS in its applicability requirements. In spite of this effort ambiguity still exists in the applicability regarding the broad statement pertaining to UFLS entities that ‘control’ UFLS equipment.
No
Although the DT’s decision to replace the discrete points in these requirements with frequency time curves that achieve the same objective, the applicability requirement in Requirement R3.3, which addresses Volts per Hz performance characteristics, lists each generator bus and generator step-up transformer high-side bus associated with generating facilities defined in sub-requirements 3.3.1, 3.3.2, and 3.3.3. The facilities listed in the above sub-requirements appear to be quoted from the NERC Statement of Compliance Registry Criteria, Sections III.c.1 & III.c.2. It is not clear why sub requirement 3.3.3 is necessary since it is simply a restatement of requirement 3.3.2. Suggest that 3.3.3 be eliminated and that 3.3.2 be re-written to be consistent with the Registry, Section III.c.2, “Generating plant/facility > 75 MVA (gross aggregate nameplate rating) or when the entity has responsibility for any facility consisting of one or more units that are connected to the bulk power system at a common bus with total generation above 75 MVA gross nameplate rating.”
No
Similar to the comment provided in response to Question 9, requirements 4.3 and 4.6 are simply restatements of requirements 4.2 and 4.5, respectively. Suggest that requirements 4.3 and 4.6 be eliminated, and that requirements 4.2 and 4.5 be rewritten to contain the language dealing with the applicability of composite facilities as defined in the Registry Criteria Section II.c.2. Additionally, this draft version of PRC-006 states in requirements 4.1 through 4.6 (as well as in requirements 3.3.1 through 3.3.3) that the assessment of non-conforming generator trip settings is limited to those generators generally defined by the Registry Criteria, rather than assuming that the Functional Entities shown in the Applicability Section of the Standard are further defined by the NERC Registry Criteria. This limitation is not necessarily valid for situations where any generator, regardless of size, is material to the reliability of the BES (Registry Criteria III.c.4). In particular during the development of a supporting Regional Standard it is quite possible that the amount of generation whose non-conforming performance characteristics may be tolerated, (and thus eliminated from assessment consideration), will be very limited. In regions where a great preponderance of the total generation is comprised of smaller units the tolerance threshold for ignoring generation below a bright line value defined by PRC-006 may invalidate conclusions of the Regional UFLS Program assessments. These conclusions presently demonstrate that the Regional Program meets the broad performance characteristics and/or requirements of PRC-006. The PRC-006 SDT should be aware that those RSDTs developing Regional Standards will, based on necessity, assess the applicability of Functional Entities and to the degree that a materiality issue is raised will bring that issue before the Regional Entity. Regional Entities would be expected to confirm that reliability is at stake prior to the issuance of a Compliance Guidance Statement, or other communication tool. The RSDT expects that the reach of applicability governing the registration and compliance obligations of any such Functional Entity identified under the “material to the reliability of the bulk power system” clause of the Registry Criteria will be clearly defined in each Regional Standard. Generation facilities which do not meet the NERC generator registration criteria could avoid obligations to meet generator underfrequency and overfrequency trip requirements presented in the standard. Significant amounts of generation categorized as such could cumulatively jeopardize the performance of a UFLS program. Possible future trends in the development of generation could increase the amount of installed generation capacity that does not meet the NERC generator registration criteria. Such trends may include the development of renewable distributed generation that is not connected to the BES system.
Yes
 
No
Limiting applicability to only the TO limits the thrust of this requirement in cases where other FM entities are responsible for switching of elements that support the UFLS program. The Drafting Team should consider modifying R4 to include a requirement to model any automatically switched elements related to a UFLS program. The Drafting Team should consider a requirement to inform the Planning Coordinator of the implementation of UFLS relay inhibit schemes (e.g. voltage inhibit) and any associated parameters. Knowledge of such information would be vital to the Planning Coordinator when assessing the performance of a UFLS program.
No
At present, the language in the implementation plan describes a one year phase in for compliance intended to provide Planning Coordinators sufficient time to develop or modify UFLS programs and to establish a schedule for implementation. NPCC has already developed an implementation plan. It must be noted that the NPCC implementation plan is a six year plan and the final language of the NERC implementation plan with regard to the overall approved term will have be closely monitored.
Yes
 
Individual
James Sharpe
South Carolina Electric and Gas
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
No
The graphical representation of the frequency-time curves alone allows plenty of margin for mis-interpretation of the curves data points. A "break-down" of the plotted curves should be clearly displayed (in conjunction with the graphical curve representation) in a table immediately below each frequency-time curve to further clarify the under- and over-frequency performance characteristic curves data points.
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Individual
John Bee
Exelon
Yes
 
No
Exelon does not agree with the concept of allowing neighboring Planning Coordinators to define or modify islanding criteria. There should be a single criteria for the determination of an island which is consistent across the interconnection, unless a specific geographic or regional exception is identified. Even if differing islanding criteria are allowed for each PC, the Planning Coordinator with responsibility for the footprint should have sole authority for determining and modifying the criteria within that footprint.
Yes
 
No
Exelon does not agree with the concept of allowing neighboring Planning Coordinators to define or modify islanding criteria. There should be a single criteria for the determination of an island which is consistent across the interconnection, unless a specific geographic or regional exception is identified. Even if differing islanding criteria are allowed for each PC, the Planning Coordinator with responsibility for the footprint should have sole authority for determining and modifying the criteria within that footprint.
Yes
 
Yes
 
No
EOP-003-1 needs to define the criteria as to when and how UVLS schemes are installed to provide consistency direction to Planning Coordinators and the entities that have to install UVLS schemes. The relationship between the use of UVLS and compliance with TPL-001 standards should be clarified. Is load shedding (including UVLS) allowed to meet the performance criteria in TPL-001? The standard should define when UVLS are applicable to the BES and thus subject to the requirements of EOP-003. UVLS schemes developed for distribution or other purposes beyond criteria should not be discouraged through regulatory burden. UVLS should be carefully defined. Many types of load will cut out on low voltage.
Yes
 
No
The standard lacks guidance as to what the trip settings should be. It is not clear as to how Attachment 1 should be used and doesn’t provide specific detail for under frequency set points. Exelon disagrees that R3.3 is easier to understand. Clarification is needed as to where the underfrequency set points are. Do all entities contribute equally to Attachment 1? There needs to be a standardized relationship between GO and TO/DP participation in obtaining the desired level of system performance. There should also be explicit criteria as to what the expectations are for each individual entity. It should be clear that all UFLS entities are to participate equally and that larger entities will not be expected to carry the burden for smaller entities. There should be some recognition in the standard that UFLS schemes currently exist and effort should be made to avoid needlessly changing relays or settings on many thousands of installations if some arbitrary and common set points were to be determined by the PC, thus causing needless expense. It is likely desireable to have slightly different settings for UFLS across a footprint so as to not create load changes that are too abrupt. The current practice of allowing contractual agreements between GOs and DPs for additional load shedding as a voluntary business decision, in the event that a unit owner doesn’t comply with the unit trip settings should be addressed.
No
Exelon feels that a table should be included with the curves. What was the source of the curves and the V/Hz requirements? The table seems to indicate that it is acceptable for the Eastern Interconnection to remain at 58.9 Hz for up to one minute. The data requirements for the assessment study should include additional data other than that for units out of compliance, i.e. all loads for the entire system as load is dropping.
No
Exelons concern is that neighboring Planning Coordinators will be making requests and setting criteria for the local planning coordinators and associated UFLS entities. We do not agree with the text “any Planning Coordinator may now select islands including interconnected portions of the BES in adjacent Planning Coordinator footprints and Regional Entity footprints, without the need for coordinating.”
Yes
 
Yes
 
Yes
 
Individual
Ernesto Paon
MEAG Power
Yes
 
Yes
 
No
Developing a VSL tool similar to the VRF tool would be beneficial. The VSL seem arbitrary. For example, R1 has a "moderate" and "high" VSL if you do not take into account historical events when documenting and developing the criteria, but what if your sub-region never had an UF event? You are still in compliance?
Yes
 
Yes
 
Yes
 
No comment.
Yes
This is an excellent language change.
Yes
 
Yes
 
Yes
 
No
What are automatic switching of elements? Does it mean that the TO needs to switch capacitor banks, or does it refer to the breakers equipped with UF relays? If it is referring to capacitor banks, is this applicable near major generation busses?
Yes
 
No comment.
Individual
Kirit Shah
Ameren
Yes
Did the SDT utilize the VRF Tool recently developed by the Process Subcommittee of the NERC SC to develop the VRFs? If not, the VRFs should be revisited using this tool.
No
In M3, it isn’t clear what is meant by “including the criteria itself.” The criteria is already specified in Requirement R3, so this phrase does not appear to be needed. M5 should only apply to PCs who would be part of a particular joint island. The present wording seems to suggest that M5 and Requirement R5 would apply to every PC. The wording for M5, and corresponding Requirement R5, should be modified to apply only to the PC’s which would be involved with a particular island.
No
For Requirement R11, the ‘Lower’ VSL needs rewording. This VSL as written is just a repeat of the requirement text. Also, the time ranges for the VSL’s should be expanded. Suggested ranges: Moderate: 12-14 months; High: 14-16 months; Severe: 16-18 months.
No
Requirement R1 should be revised to read “Each Planning Coordinator, in coordination with its constituent Transmission Owners and Transmission Planners, shall develop and document criteria…”. Further, it should include that the Regionla Entity should be involved in the studies, as in many cases, the RE has performed or were involved in thses studies. similarly, Requirement R2 should be revised to read “Each Planning Coordinator, in coordination with its constituent Transmission Owners and Transmission Planners, shall identify one or more islands…”. Requirement R3 should be revised to read “Each Planning Coordinator, in coordination with its constituent Transmission Owners, Distribution Provider and Transmission Planners, shall develop a UFLS program…” The Planning Coordinator should in all UFLS related activities include UFLS plans and procedures which their Transmission Owner, Distribution Provider and Transmission Planners may have had in place, and functioning adequately, perhaps for many years.
Yes
 
Yes
 
No
Because EOP-003-1 is the primary load shedding standard, and because UFLS has been removed from EOP-003-1 and placed in PRC-006-1, standard EOP-003-1 should note in the “Purpose” section that UFLS is addressed in PRC-006-1. The stated purpose of EOP-003-1 is to have the capability and authority to shed load rather than risk uncontrolled failure of the interconnection if there is insufficient generation or transmission capacity. It is not clear when and how it is determined that an "automatic" load shedding scheme is necessary or required. Are all TO’s required to have undervoltage load shedding plans in place? Suggest changing the ending phrase of R2 in EOP-003 from “required” to “necessary to minimize the risk of uncontrolled failure of the Interconnection.” Also suggest a review of other UVLS stanadrds for consistency with revised EOP-003.
Yes
 
No
While this is an improvement over the previous draft, we still believe that Requirement R3.3, dealing with generator V/Hz limitations, should not be part of this standard.
Yes
 
Yes
 
No
It is not clear what should be included in automatic switching. This requirement is vague. It appears that Requirement R9 would address anything that Requirement R10 would have been intended to cover.
No
The intention of R13 is good but a provision should be provided for each Planning Coordinator to comply with R11 in the event that it is not feasible to satisfy R13 within the one year assessment period. The Planning Coordinator’s compliance with R11 should not be dependent on actions by others. The 500 MW limitation discussed in the background section should be included in R11 to make sure this thought is not lost if/when the standard becomes effective. There is no need to evaluate smaller islanding events.
Yes
 
Group
SPP System Protection and Control Working Group
Shawn Jacobs
Southwest Power Pool
Yes
 
No
What is meant by “criteria” in Requirement R1? Does “criteria” in R1 have to be justified?
No
For R11, the lower VSL is stated as a requirement and not as a VSL. Does it need to be reworded?
Yes
 
Yes
 
Yes
 
Yes
 
No
Why are Generator Owners not included in the Standard? The Planning Coordinator can’t prove the design without the Generator Owner for Requirements R3 and R4.
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Group
SERC Planning Standards Subcommittee
Philip R. Kleckley
South Carolina Electric & Gas Co.
Yes
 
No
M3: It is unclear what action is intended by the phrase "including the criteria itself." Since the criteria is specified in R3, it is recommend that it be deleted. M5 and R5: This should only apply to PCs who are a part of the joint island, while the way it is currently worded it appears to apply to every PC. Recommend that the wording in M5 be changed to: "Each Planning Coordinator shall have dated evidence such as memorandums, letters, or other dated documentation that it reached concurrence with the other affected Planning Coordinators on design assessment results for any identified islands in accordance with Requirement R5 and identifies the affected Planning Coordinators." Recommend that the wording in R5 be changed to: "Each Planning Coordinator shall reach concurrence with all other affected Planning Coordinators on UFLS design assessment results before design assessment completion for any islands identified by that Planning Coordinator which include a portion of its footprint along with portions of another PC(s) footprint."
No
The Lower VSL for R11 needs work. It appears to simply repeat the requirement rather than stating a violation. Recommend that the time ranges for the VSLs addressing being late with the assestment should be expanded to Moderate 12-14 months, High 14-16 months, and Severe 16-18 months.
Yes
 
 
Yes
 
No
Because EOP-003-1 is the primary load shedding standard, and because UFLS has been removed from EOP-003-1 to PRC-006-1, standard EOP-003-1 should note in the “Purpose” section that UFLS is addressed in PRC-006-1. Suggest changing the ending phrase of R2 in EOP-003 from “required” to “necessary to minimize the risk of uncontrolled failure of the Interconnection.”
Yes
 
Yes
 
Yes
 
Yes
 
No
It is not clear what is included in automatic switching. This requirement is so vague that it does not appear to add anything in addition to the UFLS program design that it is intended to address. It appears that anything that R10 may be designed to address is already covered by R9.
No
The intention of R13 is good but a provision should be provided for each Planning Coordinator to comply with R11 in the event that R13 is not satisfied within the one year assessment period specified in R11. A Planning Coordinator’s compliance with R11 should not be dependent on actions by other Planning Coordinators. The 500 MW limitation discussed in the background section should be included in R11. There is no need to evaluate smaller islanding events.
Yes
The comments expressed herein represent a consensus of the views of the above named members of the SERC Planning Standards Subcommittee only and should not be construed as the position of SERC Reliability Corporation, its board or its officiers.
Individual
Michael R. Lombardi
Northeast Utilities
No
The VRF for Requirement R1 is stated as a Lower. The requirement to develop program criteria in Requirement R1 is as important as those requirements stated in Requirement R2 which is assigned a Medium VRF. Suggest the Requirement R1 VRF be revised to Medium.
Yes
 
Yes
Although NU agrees with the intent of the subject VSLs, we suggest that for Requirement R8 (Moderate and Severe) that the text beginning with OR is deleted. Additionally we suggest: • For Lower, Moderate and High VSLs - the first sentence be revised to read “The UFLS Entity provided data, in the format specified, to its Planning …” • For Severe VSL - the first sentence be revised to read “The UFLS Entity failed to provide data, in the format specified, to its Planning Coordinator(s) within 20 calendar days …”
Yes
 
 
Yes
 
Yes
EOP 003 is on the list of standards identified by the NERC Tiger Team for fast tracking of Order 693 directives. There is concern that coordination between these two DT’s may not have occurred and that the changes agreed upon in the revised UFLS SAR should also be considered by the Tiger Team.
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Individual
Robert Ganley
Long Island Power Authority
No
The VRF for R1 for the development and documentation of UFLS program criteria is stated as a "Low" VRF. Such a requirement to develop overall UFLS program criteria was more than a "Low" or Admininstrative requirement and that the VRF for this requirement should be listed as Medium VRF. The requirement to develop a program criteria in Requirement R1 is as important as those requirements stated in Requirement R2 which was assigned a Medium VRF by the DT.
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
No
 
Yes
 
No
 
No
 
Yes
 
Yes
 
Yes
 
Yes
 
Individual
John Bussman
AECI
Yes
 
No
: For M1, how can we consider historical events if we have never had a UFLS event on our system? How would a system study tell us how to select an island? This is unclear.
No
In R1 it is unclear how to use historical events and system studies to select portions of the BES. In R4, I can see how we should be responsible for our own generators, but the information for generation owned by others is only as good as the data we receive. In R7 for the lower VSL, up to 40 days seems like it would include 30, should it be changed to say between 30 and 40? In R11, for the lower VSL, it appears to be just a restatement of the requirement rather than a VSL.
No
It is unclear what is meant by footprint if it is not a regional entity footprint. For those of us on a heavily interconnected border between two regional entities, do we now share a footprint with them? What about other utility’s loads on our system, or vice versa, would we share a footprint with them as well? Also, R2.3 talks about if you are in multiple footprints, each of those footprints shall be identified as an island. Does that mean each footprint is a separate island or each footprint is included in the same big island?
 
 
No
R4 says voltage or power flow levels must be considered when designing an automatic load shedding scheme. Our UFLS scheme is an automatic load shedding scheme that does not take voltage or power flow levels into account. R4 needs to be reworded so that it is clear that it is ok to have automatic UFLS schemes that do not rely on under voltage or power flow levels.
No
It seems like generator owners should be added here, especially since R4 deals with generator frequency settings
No
It is unclear what the system frequency should be after the blue line ends.
No
AECI can understand how we should be responsible for our own data, but the data we use for others is only as good as the data we receive. It seems like this standard also needs to apply to generator owners
No
What if somebody else, with more stringent criteria than us, identifies us as an island and wants us to then conform to their more stringent criteria? It seems like if we did not identify them, the burden should not be placed on us. Also there seems to be potential for the actions of another utility to determine our compliance.
Yes
 
No
R13 seems unreasonable. If we do everything in our power to concur with another planning coordinator and they do not concur, our compliance is then determined by somebody else’s actions.
 
Individual
Darryl Curtis
Oncor Electric Delivery
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Individual
James A. Ziebarth
Y-W Electric Association, Inc.
Yes
 
Yes
 
No
Regarding the VSLs for R8, the UFLS entities cannot be punished for failing to meet a schedule if the schedule is not mutually agreed upon between the Planning Coordinator and the UFLS entities to ensure that the UFLS entities are capable of meeting such a schedule. At the very least, there must be some protection for the UFLS entities provided that requires the Planning Coordinator(s) to give the UFLS entities long-term notice of the deadlines that they will need to meet. The lack of any scheduling restrictions for the Planning Coordinators in the standard as written has a strong potential to cause enormous burdens on small UFLS entities that simply do not possess the resources to deal with such data reporting requirements without sufficient advance notice. Additionally, the UFLS entities cannot be penalized for failing to submit data in a format over which they have no control or input. The Planning Coordinator should be required to consult with the UFLS entities and decide upon a mutually agreeable data format in order to ensure that the UFLS entities are capable of providing the required data in the required format. With no language in the standard limiting or clarifying what data can be required of the UFLS entities by the Planning Coordinator, this provision at least should be made to protect small UFLS entities with highly limited resources for dealing with such data reporting requirements.
Yes
 
Yes
 
Yes
 
Yes
 
No
Because Load Serving Entities (not Distribution Providers) are actually responsible for the load in the current Functional Model and Compliance Registry Criteria, they should also be included in the applicability section of this standard.
Yes
 
Yes
 
Yes
 
No
Y-WEA is concerned about this requirement in that it seems to require the installation of facilities rather than just relays. 16 USC 824o (a)(3) gives NERC the authority to regulate existing facilities and planned additions or modifications to those facilities, not to prompt or require modifications or additions to the existing facilities. This proposed requirement seems to run afoul of this section of the USC.
Yes
 
Yes
 
Group
SERC SC UFLS Standard Drafting Team
Bob Jones, Chairman
Southern Company Services, Inc
Yes
 
No
M3: It is unclear what action is intended by the phrase "including the criteria itself." Since the criteria is specified in R3, it is recommend that it be deleted. M5 and R5: This should only apply to PCs who are a part of the joint island, while the way it is currently worded it appears to apply to every PC. Recommend that the wording in M5 be changed to: "Each Planning Coordinator shall have dated evidence such as memorandums, letters, or other dated documentation that it reached concurrence with the other affected Planning Coordinators on design assessment results for any identified islands in accordance with Requirement R5 and identifies the affected Planning Coordinators." Recommend that the wording in R5 be changed to: "Each Planning Coordinator shall reach concurrence with all other affected Planning Coordinators on UFLS design assessment results before design assessment completion for any islands identified by that Planning Coordinator which include a portion of its footprint along with portions of another PC(s) footprint."
No
The Lower VSL for R11 needs work. It appears to simply repeat the requirement rather than stating a violation. Recommend that the time ranges for the VSLs addressing being late with the assestment should be expanded to Moderate 12-14 months, High 14-16 months, and Severe greater than 16 months. Revise the High and Severe VSL that contain the phrase "shall conduct and document" to read: "conducted and documented." The R4 VSLs should include a consideration of the timeliness of the completion of the study (e.g. lower VSL for 3 months late, Moderate for 3 to 6 months, etc.).
No
R5 and R13 seem very problematic. The standard requires that both or all the entities agree. One entity might have larger margin requirements or a different methodology compared to another entity. These differences might not be reconcilable. We do not believe that a standard can require that one PC change its methods because a different PC does not agree with its methods, or agree that another method (any method) is acceptable that it finds a problem with. There at least needs to be a process in the event that two companies cannot agree. We recommend that the following language be added to R5: “If concurrence cannot be reached, an individual Planning Coordinator in that island can demonstrate that its UFLS scheme meets the requirements by performing dynamic simulations that apply its UFLS scheme on the entire island.” We recommend that R13 be eliminated since it is covered by R11.
 
Yes
 
Yes
 
Yes
We recommend that R3 be revised to require the PC to specifically notify the “UFLS Entities” in their PC area that are part of the PC’s UFLS program.
Yes
 
Yes
 
No
see above comment to questions #2 and #4.
Yes
It is not clear what is included in automatic switching. Illustrative examples would be helpful to clarify what is meant (e.g. automatic switching of a capacitor to avoid overvoltage). R10 refers to “Elements” and M10 refers to “Facilities.” In both R9 and R10, replace the word “provide” with “implement.”
No
As noted in our response to question #4 above, we recommend elimination of R13. The 500 MW limitation discussed in the background section should be included in R11. There is no need to evaluate smaller islanding events.
Yes
 
Group
NERC Staff
Mallory Huggins
NERC
 
 
 
Yes
NERC staff understands and supports this change to replace the groups with individual Planning Coordinators and agrees that it is a good hybrid approach. While NERC recognizes that the move might not be the ideal way to coordinate interregionally, at this point it does seem to be the best way to assign these requirements.
 
Yes
NERC staff agrees that it is wise to revise requirements specific to Underfrequency Load Shedding in EOP-003-1 to remove inconsistencies and redundancies. The only concern is that because both ad hoc team for expediting certain standards processes and the original EOP-003-1 SDT are working on modifications to the standard, there could be some overlap and miscommunication, especially with respect to these redundancies between PRC-006-1 and EOP-003-1.
Yes
NERC staff agrees that it is wise to revise requirements specific to Underfrequency Load Shedding in EOP-003-1 to remove inconsistencies and redundancies. The only concern is that because both the team of experts (formerly known as the Tiger Team) and the original EOP-003-1 SDT are working on modifications to the standard, there could be some overlap and miscommunication, especially with respect to these redundancies between PRC-006-1 and EOP-003-1.
Yes
NERC staff believes that the SDT has sufficiently identified the proper entities for UFLS coverage. NERC staff understands the comments raised by the industry regarding transfer of responsibilities, however, it is worth noting that some inconsistency has been created by the language used in the standard. It could be problematic that the entity with the original responsibility (the Distribution Provider) can delegate responsibility to another entity (the Transmission Owner), because even with that delegation, the Distribution Provider’s original responsibility does not disappear.
Yes
Yes, NERC staff supports the idea of better demonstrating coordination with the requirements proposed for PRC-024.
No
NERC staff disagrees with limiting the level of modeling in the assessments and feels that the modeling of generation should go beyond the 20 MVA and 75 MVA units as proposed. NERC staff believes that the UFLS design assessment should not be limited to modeling BES-connected resources. During a frequency excursion, all generation and frequency responsive devices “see” the excursion and react to it, regardless of size and location. Further, as penetration increases for similarly influential blocks of non-traditional resources (i.e., wind and solar farms) that have common underfrequency trip performance characteristics, it is essential that these dynamics and underfrequency trip characteristics should also be modeled and taken into account. This is not to say that each individual wind turbine or 500 kW generator must be modeled everywhere. However, when aggregate groupings of smaller units are known to be influential in dynamics analysis, or groupings of non-traditional resources with like frequency performance characteristics exist, it is essential that their influence be analyzed regardless of their voltage connection. The contribution to frequency response or common-mode tripping of such resources could mean the difference between a successful and unsuccessful UFLS system design.
Yes
 
Yes
 
Yes
 
Yes
 
Individual
Jonathan Appelbaum
United Illuminating Company
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
No
R1 should use term “shall implement manual load shedding”. The Drafting team note says that PRC-006 is a Planning Standard and therefore EOP-003 R1 is needed to apply to the actual implementation of automatic load shed. We disagree that PRC-006 is solely Planning. The UFLS entity is required to implement the program, meaning protective devices are deployed and armed. By creating the program and arming the protection systems the UFLS Entity has committed to load shed. EOP-003 R1 is addressing the steps or actions a Transmission Operator takes to respond to insufficient resources. The Transmission Operator does not initiate automatic UFLS. The UFLS program is created by the Planning Coordinator and implemented by Transmission Owners and DP. EOP-003 requires the BA and TOP to perform load shed. Again, for UFLS this implies the TOP and BA have on/off control for UFLS protection systems. This we know is not true. The TOP/BA has the authority to implement manual load shed. A similar argument is made for R3. R3 should be “coordinate manual load shed plans”. Coordinating plans is a Planning Horizon exercise. Therefore EOP-003 R3 coordination of ufls load shed by TOP/BA is a duplicate function to the PRC-006 coordination by Planning Coordinators. The entity with the best knowledge to coordinate UFLS is the Planning Coordinator. TOP and BA are coordinating the manual load shed plan with the recognition the UFLS is installed. In R5 add the words “automatic load shedding scheme other than UFLS”. This will help compliance monitoring by explicitly differentiating this from PRC-006. Update the VSL also with this clarification.
Yes
 
Yes
 
Yes
 
Yes
Replace "reach" with "obtain".
Yes
 
Yes
 
Yes
 
Individual
Kasia Mihalchuk
Manitoba Hydro
No
The VRFs for R3, R4, R9, and R10 should be reduced from “High” to “Medium” for several reasons. System events that would activate automatic underfrequency load shedding have been very rare and automatic UFLS is a system preservation measure of last resort, not primary system preservation measure. For R4 in particular, the performance of the UFLS program and the associated islands do not change rapidly or dramatically to warrant a “High” VRF for delayed conducting or documentation of a UFLS design assessment.
No
Suggest that the measures be modified to reflect any changes made to standards Requirements per the comments made to questions Q4 through Q13. M10 – Replace “automatic switching of Facilities” with “automatic switching of Elements” to be consistent with the associated Requirement R10.
Yes
 
Yes
 
 
No
We propose that the scope of the SAR be revised to call for removing the automatic UFLS requirements from EOP-003-1 and moving them to PRC-006-1 standard, and for removing the automatic UVLS requirements from EOP-003-1 and moving them to a new PRC standard
No
In line with the comments for Question 6: R2 - remove this requirement because it refers to automatic load shedding plans, let this be covered by PRC-006-1 and a new PRC standard. R3 – add the qualification “coordinate manual load shedding plans”. R4 - remove this requirement because it refers to automatic load shedding plans, let this be covered by PRC-006-1 and a new PRC standard. R5 – add the qualification “implement manual load shedding plans”. R7 - remove this requirement because it refers to automatic load shedding plans, let this be covered by PRC-006-1 and a new PRC standard.
Yes
 
No
1. In R3, the term, “imbalance”, should be described using the standard industry nomenclature of imbalance = (load-generation)/generation. The present definition defines imbalance as being the same as the required percent load to be shed, and if this is what is intended, it would be better to keep it simple say that everyone needs to shed at least 25% load and avoid use of the term imbalance. In any event, the definition of “imbalance” should follow industry conventions for consistency. For R4.1, R4.2, R4.3 - Attachment 1 and 2: 2. The titles for Attachment 1 and 2 should clearly qualify that the transient frequency performance curve applies for a 25% or less island imbalance and that programs which are larger than this minimum load shedding requirement do not have to meet this criteria when overloads are in excess of 25%. [If the SDT doesn’t allow different characteristics for a higher than 25% program, then we propose that the MRO submit a variance for a 30% and higher UFLS programs.] We are quite concerned that the generation tripping curve part of attachments 1 and 2, which matches the curve in PRC-024, as it appears to that this applies to all overload levels and to any size of load shedding program. It can be easily demonstrated that as the size of the load shedding program is increased, that generation protection settings have to be modified accordingly. The reason is to achieve coordination objectives. When we are dealing with the larger imbalances we are also inherently dealing with lower minimum frequencies and longer frequency recovery times. To make matters worse, we are trying to approve PRC-006 using information from PRC-024 which is still a draft, not an approved standard. We would like to elaborate on problems related to the generation protection curve part of attachment 1: UFLS programs have to deal with several mutually conflicting objectives and by setting hard and fast limits for generation underfrequency protection up front, we are adding an unnecessary constraint which will have undesirable effects on other aspects of the program. Such generation protection settings have to be considered in the context of the overall set of compromises that go into UFLS program design. We have to consider what kind of frequency recovery can be achieved with a well coordinated load shedding program and we have to compare that performance to the true capabilities of the generation in the island. When all things are considered, a final compromise can be reached that gives the best of all worlds. The characteristic in PRC-024 is not representative of the raw data from the manufacturers that defines actual capabilities, instead it is just someone’s estimation of what is a reasonable tradeoff, and represents some hypothetical amount of accelerated loss of life of the turbine. The generation protection curve from PRC-024 is at best a starting point. From a design perspective, we could use different and equally valid settings if needed. 3. The Under Frequency Performance Characteristic line in Attachment 1 should be extended from the knee at approximately 58.9 Hz (for 60 seconds) to 59.3 Hz or 59.6 Hz (at for approximately 500 sec). The purpose is to define a single line of constant slope and to get rid of the arbitrary knee in the characteristic which serves no reliability purpose. The reason for this change is that the worst case frequency recovery time for frequencies between 58.7 Hz and 59.5 Hz may occur for imbalance conditions significantly less than 25% where the governor response prevents the load shedding blocks from picking up and where frequency recovery times is are a function of governor response and system inertia. Likewise it makes sense to extend this line below 58 Hz to at least as low of a frequency as is covered by the generation protection curve spicily for the hydro generator as of Manitoba Hydro case. 4. Add a note to Attachment 1 that states, "Larger size UFLS programs (e.g., 60%) may require less restrictive (lower) underfrequency (as well as and/or longer time delays) due to island generation and protection characteristics. UFLS programs shedding more than 25% must also increase generation protection delay times and/or change set points to achieve coordination with load shedding. For example, Manitoba Hydro needs to shed more than 30% of the area load to achieve reasonable frequency recovery in it island. In this case, the shedding of a higher percentage of load may allow the frequency to drop below 58.2 Hz for longer than 4 seconds, but the subsequent impacts on the hydro generator in these islands are acceptable. For R4.4, R4.5, R4.6 - Attachment 2: Generator Underfrequency and Overfrequency Attachments: 5. The Generation Owner off-nominal frequency coordination requirements and coordination curves should be included in the PRC-006 standard and PRC-024 should be scrapped. How can PRC-006 even proceed with using curves from PRC-024 when PRC-024 is still being drafted and subject to change? We could approve PRC-006 only to find subsequent changes to PRC-024 have undermined everything. The generation curves which are used to set generation underfrequency protection need to be appropriate for the system studied and one size does not fit all. The generation protection curves in Attachments 1 and 2 appear to be someone’s personal estimation of what is a reasonable amount of accelerated loss of life per event but the flaw is that this was developed without first finding out what is really needed to ensure a well coordinated UFLS plan that meets all of the other objectives (planning engineers need to be able to coordinate generation protection with load shedding frequency recovery times as part of the study process, as the recovery times are influenced by the design objectives of the UFLS program). This generation off-nominal frequency characteristic is not what manufacturers provide as limits on their machines. No technical justification was ever provided for these curves that were developed in PRC-024, and that justification is needed. It is insufficient to say that PRC-006 is justified in using this just because it came from PRC-024. The technical justification was never part of any NERC standards drafting effort. Limits of this nature should not be created arbitrarily, and have to be selected as part of the overall final compromise involved in UFLS design to ensure we give enough time for load shedding to operate under worst case conditions, and as much time as possible needs to be given for frequencies close to 60 Hz as UFLS events show that in the real world that things do not always work as planned and system frequency can stall out below 59.5 hz for a long time while operators try to deal with this by manually shedding load. If the generation protection curves are not appropriate for programs covering overloads beyond 25%, then the titles of the curves should qualify that they apply for a 0% to 25% imbalance and include an note that different settings may be needed to coordinate with UFLS programs that shed more than 25% of the island load. Volts/Hertz Performance Characteristic: 6. The Volts/hertz requirement is not need in this standard. There are a couple of reasons. Voltage regulators automatically reduce voltage according to volts per hertz when in the automatic mode so they self protect. Industry recommendations/standards (IEEE C37.102 or IEEE C37.106, ANSI C50.13-1989, IEEE C57.12.00-2000) already exist that adequately address the volts/Hz issue. If voltage regulators are in automatic, the 110% volts/Hz limit kicks in between 57.2 Hz and 61.8 Hz assuming the voltage regulator holds terminal voltage within the allowed 1.05 pu to .95 pu range. Units with voltage regulators in manual will just trip when volts per Hertz protection picks up. Units are normally in automatic control so this is not a big worry. It appears this requirement is appropriate for programs which may experience frequencies below 57.2 Hz, but few programs will see frequencies this low. Of course that makes it very easy to demonstrate that programs satisfy this requirement, but it still seems there is no need to put this in the standard. As such, we believe the Volts/Hz requirement is of questionable worth for programs covering overloads of up to 25%, and should be removed. Even if system frequency were to drop below 57.2 hz, this performance characteristic cannot presently be properly simulated in stability cases as the voltage regulator V/Hz controls are not presently included in generator exciter/voltage regulator models of the present power system modeling programs that are used for dynamic power system simulation.
Yes
 
No
Replace the words “reach concurrence with” with “provide UFLS design assessment results to”. Fulfillment of a compliance measure that involves reaching concurrence with another entity is dependent on the other entity and can be outside of the control of the Planning Coordinator. In addition, replace the words “other affected Planning Coordinators” with “other Planning Coordinators that have design assessment responsibilities for islands covered in the design assessment report. The qualification of “other affected Planning Coordinators” is too vague and could be interpreted and categorized differently by various entities and auditors.
Yes
 
No
1. For R11, replace “Each Planning Coordinator, in whose footprint . . . to evaluate” with “When a disturbance event occurs in a Planning Coordinator’s footprint that involves automatic UFLS program operation or frequency excursions should have activated UFLS program operation, and a final disturbance report is required per EOP-004, each Planning Coordinator shall evaluate within one year of the disturbance event:”. 2. We have concerns about specifying that the evaluation must be complete within one year we know that some historical studies of events that included UFLS took longer than one year [e.g., three years] to complete. Therefore, we would prefer a more flexible wording, a longer time frame to be used in this requirement. Perhaps the requirement could stipulate that the evaluation must begin within 6 months and be completed within the schedule set by the investigative team. 3. For R13, replace “in whose footprint . . .on the event assessment result” with “that conducts an UFLS design assessment (per R12) for islands where other Planning Coordinators have design assessment responsibilities shall provide a design assessment report to those Planning Coordinators.” The reference to the event assessment report should be part of R11. The qualification of “event affecting multiple Planning Coordinators” is too vague and could be interpreted and categorized differently by various entities and auditors.
Yes
We are contemplating a variance. However, this variance must apply to other areas such as Manitoba Interconnection within MRO to address the physical characteristics of the Manitoba system. Manitoba system physical characteristics are very much similar to Québec system. More than 90 % of installed generation in the Manitoba Interconnection is hydraulic. Manitoba Hydro may provide modifications to attachments 1B and 2B that would be applicable for Manitoba hydro area and cover UFLS program for an imbalance of more than 25%.
Individual
Edward Davis
Entergy Services
Yes
We recommend that the VRF Tool be used to validate the proposed VRFs.
No
M3: It is unclear what action is intended by the phrase "including the criteria itself." Since the criteria is specified in R3, it is recommend that the phrase be deleted. M5 and R5: This should only apply to PCs who are a part of the joint island, while the way it is currently worded it appears to apply to every PC. Recommend that the wording in M5 be changed to: "Each Planning Coordinator shall have dated evidence such as memorandums, letters, or other dated documentation that it reached concurrence with the other affected Planning Coordinators on design assessment results for any identified islands in accordance with Requirement R5 and identifies the affected Planning Coordinators." Recommend that the wording in R5 be changed to: "Each Planning Coordinator shall reach concurrence with all other affected Planning Coordinators on UFLS design assessment results before design assessment completion for any islands identified by that Planning Coordinator which include a portion of its footprint along with portions of another PC(s) footprint."
No
The Lower VSL for R11 needs work. It appears to simply repeat the requirement rather than stating a violation. Recommend that the time ranges for the VSLs addressing being late with the assestment should be expanded to Moderate 12-14 months, High 14-16 months, and Severe greater than 16 months. Revise the High and Severe VSL that contain the phrase "shall conduct and document" to read: "conducted and documented." The R4 VSLs should include a consideration of the timeliness of the completion of the study (e.g. lower VSL for 3 months late, Moderate for 3 to 6 months, etc.).
No
R5 and R13 seem very problematic. The standard requires that both or all the entities agree. One entity might have larger margin requirements or a different methodology compared to another entity. These differences might not be reconcilable. We do not believe that a standard can require that one PC change its methods because a different PC does not agree with its methods, or agree that another method (any method) is acceptable that it finds a problem with. There at least needs to be a process in the event that two companies cannot agree. We recommend that the following language be added to R5: “If concurrence cannot be reached, an individual Planning Coordinator in that island can demonstrate that its UFLS scheme meets the requirements by performing dynamic simulations that apply its UFLS scheme on the entire island.” We recommend that R13 be eliminated since it is covered by R11.
 
Yes
 
Yes
 
No
1. We recommend that R3 be revised to require the PC to specifically notify the “UFLS Entities” in their PC area that are part of the PC’s UFLS program of the UFLS program. 2. We are also concerned that the Planning Coordinator is responsible to develop a UFLS program that incorporates information from Generator Owners (R3-R3.3.3) but there is no requirement that Generator Owners provide this information. We are aware that PRC-024 (Project 2007-09) contains reporting requirements (R3, R4 and R5) but are not certain that the tables in PRC-024 match those in PRC-006 nor is there any guarantee that PRC-024 will be FERC approved without change. Therefore, we request that this standard be made applicable to GOs and those GOs provide the required information.
Yes
 
Yes
 
No
See above comment to questions #2 and #4.
Yes
It is not clear what is included in automatic switching. Illustrative examples would be helpful to clarify what is meant (e.g. automatic switching of a capacitor to avoid overvoltage). R10 refers to “Elements” and M10 refers to “Facilities.”, please change one of the references for consistency. In both R9 and R10, replace the word “provide” with “implement.”
No
As noted in our response to question #4 above, we recommend elimination of R13. The 500 MW limitation discussed in the background section should be included in R11. There is no need to evaluate smaller islanding events.
Yes
 
Group
Bonneville Power Administration
Denise Koehn
BPA, Transmission Reliability Program
Yes
 
No
Measures are too vague, lacking specifics, and not performance-based. This would leave too much up to the Auditor’s interpretation. Measures are only valuable if they contain specific targets or specifications that clarify how an entity will be deemed to be compliant with the standard as written. Measures which merely repeat the standard with the inclusion of “shall have evidence such as…” are not very useful. Measures should be explicit, detailed, consistent, and provide useful guidance to entities. These measures do not provide any useful guidance beyond what is specified in the requirement itself.
No
Criteria are never actually defined in the requirements. Planning Coordinator footprints are not established. What does “annually maintain” mean? Does it mean the Database requires annual updates, annual reviews or just to provide a database annually? Frequency excursions precede an islanding event. I.e. low frequency initiates UFLS which should prevent an unintentional islanding event. The wording of this requirement makes it seem like the islanding event occurs first and causes the UF.
No
It doesn’t make sense to assign responsibilities to organizations that are not currently formed. Footprint or jurisdiction of Planning Coordinators has not been established and no mechanism exists for assigning a specific UFLS entity into a PC’s jurisdiction. PCs within an interconnection should be required to develop an Interconnection Coordinated UFLS Plan. UFLS works on interconnection basis not on PC footprint basis. The purpose of the UFLS Plan is to mitigate the need to form islands by balancing loads and resources; a secondary function would be to balance the loads and resources after the islands have been formed. Frequency is an interconnection issue not an individual island issue and therefore not driven by an individual PC but by a coordination of PCs efforts within the interconnection.
 
Yes
 
No
EOP-003-1 and the current version of EOP-003-2 still include automatic UFLS. EOP-003-2 should include reference to manual load shed only. To include UFLS that is undefined would cause a conflict with PRC-006.
No
LSE should also be included as a “possible” UFLS entity some large interruptible customers outside of DP or TO could be allowed to own UFLS devices. In addition to the issue previously stated concerning PC authority, no valid way exists to determine which registered entities are under the jurisdiction and authority of any Planning Coordinator. The current version does not address customer-owned UFLS relays. There should be recognized sub-area group(s), which consists of PCs, as assigned by the Regional Assurer (RA) which is the agent(s) for overall coordination within the interconnection or sub-area. For example in the WECC, the RA recognizes the following sub-area groups for UFLS coordination within the Interconnection: Southern Islanding Load Tripping, Northwest Power Pool UFLS Group and the WECC Off-Nominal Frequency Load and Restoration Plan. Without the RA assuring coordination of the sub-area groups, PCs could randomly or arbitrarily form sub-area groups whose plans do not coordinate nor address the interconnection reliability needs.
No
Each interconnection should establish discrete set points based upon stability and dynamic analysis. Discrete set points can help establish criteria which are measurable and performance-based for the applicable entities. The existing analysis tools available are unable to model continuous time/frequency curves and therefore specific measurements for all entities cannot be defined leaving the performance at the discretion of the PC. The Standard needs to be very explicit that the curves are interconnection performance curves and not entity specific set points. What is the technical justification and correlation of the curves to the UFLS Plans, i.e. where did these curves come from?
No
Underfrequency is an issue of load to generation balance regardless of the voltage of the interconnection.
No
If each Planning Coordinator may choose its islands, what then is the process for getting “Planning Coordinators to reach concurrence on the UFLS assessments for any islands identified by any one Planning Coordinator”. Who is the final authority and how is the arrangement memorialized and notified? No clear definition of a Planning Coordinator footprint may impact adequate identification of and authority related to establishing concurrence.
No
Requirement R10 is unclear and needs to be rewritten to clearly address the applicability.
No
Requirement R13 needs to rewritten because language is unclear, i.e. what is meant by “of UFLS actuated loss of load”?
No
The standard and performance requirements should reflect the individual interconnections and not a continent-wide standard. This would allow for the uniqueness of each interconnection to be addressed similar to Hydro Quebec’s variance. Other Comments: While the concern for loss of additional generation units because of their V/Hz protection schemes is understood, the bases for the 1.18pu and 1.1pu values are not evident and may not be technically supportable when compared against actual protection settings or allowable post-contingency voltage bands. Further, V/Hz protection settings vary across the system and it is unlikely adherence to this requirement will impact reliability. It will only increase dynamic analysis requirements. We recommend removing R3.3.
Group
Western Electricity Coordinating Council
Steve Rueckert
WECC
No
We agree that the proposed VRFs are appropriate for the subject of the requirements, but we do not agree with many of the requirements as drafted, so we are opposed for that reason
 
No
R1 unclear definition of “criteria” it is never actually defined in the requirement. R2 For clarity Severe level should use the term “greater than 2” of the parts instead of “all” of the parts R3 For clarity Severe level should use the term “greater than 2” of the parts instead of “all” of the parts R4 no comment OK R5 very difficult to apply since Planning Coordinator footprints are not established. VSL could be based on number of adjacent PC’s that do not concur. R6 Not clear on what “annually maintain” means. Does it mean the Database requires annual updates, annual reviews or just the ability to provide a database annually? R7 at least some of the severity level should be based on the number of requests that were late rather than the time the request was overdue particularly since only an “annual maintenance” is required there is no difference in reliability impact if delivery is made in 30 or 60 days. R8 at least some severity level should be dependent on the lack of sufficiency of data as opposed to the amount of time it was overdue. R9 No comments I will assume the percentages have some basis and are not just arbitrary. R10 No comments I will assume the percentages have some basis and are not just arbitrary. R11 With respect to the VSLs I would recommend not combining the time duration and inclusion of parts. Use timing for lower and moderate and the lack of components for High and Severe. I have to be dumb here with the wording of the requirement. Does not the frequency excursion precede the islanding event. i.e. low frequency initiates UFLS which should prevent an unintentional islanding event. The wording of this requirement makes it seem like the islanding event occurs first and causes the UF This Requirement and VSL places emphasis on performing analysis and does not address any possible violation for actually having an inadequate UFLS program resulting in unintended islanding. R12 VSL should be binary. Severe for failure to perform the assessment in the required time. Actually the Requirement should be to “implement” the changes and correct the deficiencies not just to “consider” them in another assessment. If implementation were the focus the VSL’s could be based on amount of implementation completed within a specified time frame. R13 See comments for R5 with respect to PC footprint and also there is no clear indication of what is meant by event affecting other PC’s does this mean islanding in the other areas or UF load shed or equipment switching?
No
The PCs within an interconnection should be required to coordinate a UFLS Design with all other PCs within the Interconnection and the PCs should be required to develop an Interconnection Coordinated UFLS Plan. UFLS works on interconnection basis not on PC footprint basis. The primary purpose of the UFLS Plan is designed to mitigate the need to form islands by balancing loads and resources. It is a secondary function to balance the loads and resources after the islands have been formed. Frequency is an interconnection issue not an individual island issue and therefore not driven by an individual PC but by a coordination of PCs efforts within the interconnection. From an audit and enforcement standpoint, no mechanism exists for assigning a specific UFLS entity into a PC’s jurisdiction. This has the potential for making this standard unauditable for any entity which is not designated by a PC unless some guidance is established to determine a PC’s footprint.
Yes
This really doesn't look like a question, and it appears the actual question is asked in number 6.
Yes
 
Agree with the removal of the words underfrequency and Balancing Authority in EOP-003, but do not agree with the EOP-003-1 or the current version of EOP-003-2 that is out for vote because it still includes automatic UFLS. EOP-003-2 should include reference to manual load shed only. It includes UFLS that is undefined and could cause a conflict with PRC-006.
No
LSE should also be included as a “possible” UFLS entity Some large interruptible customers outside of DP or TO could be allowed to own UFLS devices. There should be a recognized sub-area group(s), which consist of PCs, as assigned by the Regional Assurer (RA) which is the agent(s) for overall coordination within the interconnection or sub-area. Without the RA assuring coordination of the sub-area groups, PCs could randomly or arbitrarily form sub-area groups whose plans do not coordinate nor address the interconnection reliability needs.
No
The devices which implement UFLS must have discrete setpoints. The standards must establish criteria which is measurable. This type of criteria is only measurable by study or actual performance following a UFLS event. The planning criteria may use curves but these must be translated to a setpoint which can be verified. Each interconnection should establish discrete set points based upon stability and dynamic analysis. From discrete set points one can establish criteria which are measurable and performance based for the applicable entities. The existing analysis tools available are unable to model continuous time/frequency curves and therefore specific measurements for all entities cannot be defined leaving the performance at the discretion of the PC. The Standard needs to be very explicit that the curves are interconnection performance curves and not entity specific set points. What is the technical justification and correlation of the curves to the UFLS Plans, i.e. where did these curves come from?
No
Underfrequency is an issue of load to generation balance. It does not seem to make sense to make the distinction of whether or not a generator or generating facilities directly connect to the BES. The loss of 100MW of generation has the same impact on frequency if they are connected at 69kv or 500kv. The thresholds used in the standards are registration thresholds for the GO/GOP function and do not negate the impact of all generation on frequency response.
No
From an enforcement standpoint there is concern that if Planning Coordinator may choose its islands, what then is the process for getting “Planning Coordinators to reach concurrence on the UFLS assessments for any islands identified by any one Planning Coordinator”. Who is the final authority and how is the arrangement memorialized and notified? Also, please see comment to Question #8 concerning the role of the RA.
Requirement R10 is unclear and needs to be rewritten to assure the applicability.
From and enforcement standpoint whom is the final authority and how are arrangements memorialized and notified? In addition these requirements address issues which indicate a failure or inadequacy of the initial required planning process and appear overall to allow PC to establish a program based on inadequate study and then fix it after an event which proves the program was inadequate. All without any violation of standard.
The standard and performance requirements should reflect the individual interconnections and not a continent wide standard allowing for the uniqueness of each interconnection to be addressed similar to Hydro Quebec’s variance. There is not a place to provide a response to question 15 from the unofficial word verison, so it is being provided here. Q 15 While the concern for loss of additional generation units because of their V/Hz protection schemes is understood, the bases for the 1.18pu and 1.1pu values are not evident and may not be technically supportable when compared against actual protection settings or allowable post-contingency voltage bands. Further, V/Hz protection settings vary across the system and it is unlikely adherence to this requirement will impact reliability. It will only increase dynamic analysis requirements. We recommend removing R3.3.
Individual
Bob Thomas
Illinois Municipal Electric Agency
Yes
For R8, R9, R10 applicable to UFLS entity/TO.
Yes
For M8, M9, and M10 applicable to UFLS entity/TO.
 
Yes
 
 
 
 
Yes
Tbe SDT's consideration of comments during the second posting is very much appreciated. Applicability now reoognizes and preserves the widely used practice of a TO factoring interconnected DP (that does not own or operate UFLS equipment) load into the TO UFLS scheme.
 
 
 
Yes
 
 
 
Individual
Jon Kapitz
Xcel Energy
No comments
No comments
No comments
No
The problem still exits that the mapping of Planning Coordinators to ‘subordinate’ entities is not clear. Creating additional requirements for a functional entity that is still nebulous creates more confusion. We also believe the term “island” should be a defined NERC term. It is used throughout the standard with the meaning being generally understood within the industry but not explicitly stated.
No comments
No comments
No comments
No
We question why Generator Owners are not included as a UFLS entity. Under R4 PCs are required to obtain setting from them. We are not aware of another standard that requires GOs to provide those settings to the PC. Thus there should also be a requirement indicating that GOs (or UFLS Entities) provide data requested by the PC to conduct the required assessments.
No comments
No
We feel that our comment in the previous draft was not fully addressed. The dynamic simulation would need to include any small generators (<20MVA or <75MVA aggregate) that are not required to register, but together, could have a material impact on the BES. Additionally, it would need to be clear who is responsible for ensuring those material impacts are included in models/simulations. Distributed Generation (DG) is a growing concern that can have an impact on UFLS programs. Consider the need for adding that the assumptions related to DG be included in the R3 & R4 requirements Additionally, the Statement of Compliance Registry lists additional criteria for generator registration (i.e. black start, determined to be material to BPS). Shouldn’t these be captured, or a more simple approach may be that all registered GOs be required to provide the requested data?
Yes
As long as the requirement as written still permits PCs to coordinate and select one or more islands between them to consider we are ok. Please clarify that R1 does not require that each PC must come up with their own unique island to consider.
No
We have concerns that R9 & R10 provide the Authority of a PC to direct investment and actions to another entity, without the agreement from that entity. Thus we feel that R5 should be modified to require concurrence from each affected UFLS Entity as well.
No
We don’t believe these should be limited to islanding events. Suggest rewording to indicate that “events resulting in frequency excursions below initializing set points of the UFLS program, or actuate automatic switching or tripping shall …”
No comments
Individual
Jeff Nelson
Springfield Utility Board
Yes
 
Yes
 
Yes
 
Yes
There remains some abiguity with regards to the following language: "UFLS entities shall mean all entities that are responsible for the ownership, operation, or control of UFLS equipment as required by the UFLS program established by the Planning Coordinators. Such entities may include one or more of the following: 4.2.1 Transmission Owners 4.2.2 Distribution Providers" SUB is fine with the Planning Coordinator having the authority to determine UFLS requirements and affected entities. But there is a problem with regards implementation of a Planning Coordinator decides that equipment is required where it was not previously required by an entity. What is the process for the Planning Coordinator to provide notice to a registered entity (such as a Distribution Provider)? If a UFLS is required of a DP where a UFLS did not previously exist, what is the implementation plan for becoming compliant without having to be out of compliance on Day 1 just becuase a PC sent a letter? Under the implementation plan where it states: "The one year phase-in for compliance is intended to provide Planning Coordinators sufficient time to develop or modify UFLS programs and to establish a schedule for implementation." Is this language intended for the PC to establish a schedule for implimentation of affected entities that fall under the standard after the standard is adopted?
Yes
 
 
 
 
 
 
 
 
 
 
Group
Tennessee Valley Authority (TVA)
Dennis Chastain
Power System Operations
No
TVA believes the following VRF changes should be considered: R4 - change from High to Medium. Justification: The selection of a 5-year interval for assessments seems subjective in nature. Failure to perform an assessment within a 5-year interval would not directly cause or contribute to bulk electric system instability. R11 - change from Medium to Low. Justification: documenting a post event assessment seems more administrative in nature, relative to R12.
No
TVA believes the following changes to the Measures should be considered: M3: It is unclear what action is intended by the phrase “including the criteria itself.” Since the criteria are specified in R3, it is recommended that it be deleted.
No
The Lower VSL for R11 needs work. It appears to simply repeat the requirement rather than stating a violation. Recommend that the time ranges for the VSLs addressing being late with the assessment should be expanded to Moderate 12-14 months, High 14-16 months, and Severe greater than 16 months. Revise the High and Severe VSL that contain the phrase "shall conduct and document" to read: "conducted and documented." The R4 VSLs should include a consideration of the timeliness of the completion of the study (e.g. lower VSL for 3 months late, Moderate for 3 to 6 months, etc.).
Yes
 
Yes
 
Yes
TVA supports this direction to remove the automatic load shedding components (UFLS and UVLS) from EOP-003 to avoid potential conflict with the PRC standards that address UFLS and UVLS.
No
TVA supports the modifications to the EOP-003 standard which remove UFLS. We believe that EOP-003 should continue to be revised under the appropriate project to focus the emphasis on load shedding plans that are controlled by operator action, and exclude automatic protection schemes (UFLS and UVLS) that do not require operator action to execute their designed function. We have the following comments on the proposed modifications: R2 - We recommend that the text added at the end of this requirement be removed (“if the Transmission Operator or its associated Transmission Planner(s) or Planning Coordinator(s) determine that an under-voltage load shedding scheme is required.”). This addition introduces entities that are not identified in the “Applicability” section of the standard (A.4). While simulations performed in the planning environment (TPL standards) would likely lead to this determination, references to the Transmission Planner and Planning Coordinator in this requirement will introduce compliance confusion. Can the SDT point to another standard that requires the Transmission Planner or Planning Coordinator to determine if an under-voltage load shedding scheme is required? Our preference would be to strike requirement R2 from the EOP-003 standard altogether, but we realize the scope of this project is limited to UFLS. R4 - With the deletions that are being proposed, we recommend that “undervoltage” be inserted into the requirement for clarification -- “automatic undervoltage load shedding scheme”. R7 - Since the Balancing Authority has been removed, suggest changing “their areas” to “their area” (singular).
No
Our preference is that the applicability section of the standard remain “clean” with regard to the applicable entities listed, and not cluttered with qualifiers. For instance, we see no benefit in listing Transmission Owners twice (4.2.1 and 4.3). If this format is retained, we suggest that section 4 be revised to add clarity. We suggest that section 4.2 be revised to read: “UFLS entities shall mean all entities that are responsible for the ownership, design, or installation of UFLS equipment or automatic switching of Elements as required by the UFLS program established by the Planning Coordinators. Such entities may include one or more of the following: 4.2.1 Transmission Owners 4.2.2 Distribution Providers” and that 4.3 be deleted. The terms “operation” and “control” are typically used in the context of an operating entity task (RC, TOP, GOP, BA). Therefore we prefer the use of “ownership, design, and installation” over “ownership, operation, or control”. The omission of the Generator Owner from this standard is potentially problematic in that coordination with generator under- / over-frequency settings is needed. We also note that PRC-008-0 contains the phrase “required by its Regional Reliability Organization to have a UFLS program”. Should this be changed to “required by its Planning Coordinator to have a UFLS program” to align with the proposed changes to PRC-006-1? Lastly, with the modifications to EOP-003, there is no linkage of operating entity applicability to UFLS. While beyond the scope of this drafting team’s objectives, we believe that operator awareness of UFLS installations is a critical component of load restoration following an event that initiates UFLS tripping.
Yes
 
Yes
 
No
R5 (and M5) is problematic in that it requires all affected PCs to reach concurrence. One PC might have larger margin requirements or a different methodology compared to another PC. These differences might not be reconcilable. We do not believe that a standard should require that one PC change its methods because another PC(s) does not agree with its methods, or agree that another method is acceptable that it finds a problem with. There needs to be a process in the event that PCs cannot reach concurrence. We recommend that the following language be added to R5: “If concurrence cannot be reached, an individual Planning Coordinator in that island can demonstrate that its UFLS scheme meets the requirements by performing dynamic simulations that apply its UFLS scheme on the entire island.”
No
It is not clear what is included in automatic switching. If it is the automatic switching of Elements for the sake of removing load, it would appear to be covered under R9. R10 refers to “Elements” and M10 refers to “Facilities”. In both R9 and R10, suggest replacing the word “provide” with “implement”.
No
TVA agrees with the intent of transitioning post-event analysis from PRC-009-0 to the proposed PRC-006-1 standard, but has the following comments: R11: The “500 MW or greater” threshold included in the background information should be included in R11. R13/M13: TVA has similar concerns with the requirement to reach concurrence with other affected PCs that are expressed in response to Question 11 for R5/M5. We recommend elimination of R13/M13, or the addition of language that would eliminate the compliance of a PC having dependency on the concurrence of one or more other PCs.
Yes
 
Individual
Charles Lawrence
American Transmission Co.
No
he VRFs for R3, R4, R9, and R10 should be reduced from “High” to “Medium” for several reasons. System events that would activate automatic underfrequency load shedding have been very rare and automatic UFLS is a system preservation measure of last resort, not primary system preservation measure. For R4 in particular, the performance of the UFLS program and the associated islands do not change rapidly or dramatically to warrant a “High” VRF for delayed conducting or documentation of a UFLS design assessment.
No
M5 - As noted in the comments below for R5, replace the words “reached concurrence with” with “provided a UFLS design assessment report to”. Fulfillment of a compliance measure that involves reaching concurrence with another entity is dependent on the other entity and can be outside of the control of the Planning Coordinator. In addition, replace the words “other affected Planning Coordinators” with “other Planning Coordinators that have design assessment responsibilities for islands covered in the design assessment report. The qualification of “other affected Planning Coordinators” is too vague and could be interpreted and categorized differently by various entities and auditors. M7 – As noted in the comments below for R7, replace “within their Interconnection”, with “that have design assessment responsibilities within the islands covered by the UFLS database”. Planning Coordinators that are within the same Interconnection, but are not within any islands covered by another Planning Coordinators UFLS database, would not need to receive the UFLS information. M10 – Replace “automatic switching of Facilities” with “automatic switching of Elements” to be consistent with the associated Requirement R10.
Yes
 
Yes
 
Yes
 
No
We propose that the scope of the SAR be revised to call for removing the automatic UFLS requirements from EOP-003-1 and referring them to PRC-006-1 standard, and for also removing the automatic UVLS requirements from EOP-003-1 and referring them to a new PRC standard.
No
In line with the comments for Question 6: R2 - remove this requirement because it refers to automatic load shedding plans, let this be covered by PRC-006-1 and new PRC standard. R3 – add the qualification “coordinate manual load shedding plans”. R4 - remove this requirement because it refers to automatic load shedding plans, let this be covered by PRC-006-1 and a new PRC standard. R5 – add the qualification “implement manual load shedding plans”. R7 - remove this requirement because it refers to automatic load shedding plans, let this be covered by PRC-006-1 and a new PRC standard.
Yes
 
No
1. In R3, the term, “imbalance”, should be described using the standard industry nomenclature of imbalance = (load-generation)/generation. 2. In R4, we interpret that the Equivalent Inertia Analysis is a valid dynamic simulation methodology for certain aspects of UFLS assessments. So, we expect that this type of dynamic analysis would be accepted toward compliance with the “through dynamic simulation” portion of this requirement Attachement 1 for R4.1, R4.2, R4.3 3. The title for Attachment 1 should clearly qualify that this curve applies for a 25% or less island imbalance. The curves that should be used for UFLS programs associated with imbalance levels greater than 25% (e.g. 30%, 40%, 50%) would be different from the 25% curve. 4. The Under Frequency Performance Characteristic line in Attachment 1 should be extended to 59.5 Hz (at 500 sec). The reason for this change is that the worst case response between 58.7 Hz and 59.5 Hz may occur for imbalance conditions significantly less than 25% where the governor response prevents the load shedding blocks from picking up and where response recovery times is a function of governor response and system inertia (30 seconds to 500 seconds). This removes the knee of the curve at 30 seconds and extends the curve up to 500 seconds. This would change the 30 second at 58.9 Hz cut off point to 500 seconds. 5. Add a note to Attachment 1 that states, "Larger size UFLS programs (e.g., 40%) may require less restrictive (lower and/or longer time delays) underfrequeny limits due to island generation and protection characteristics." UFLS programs shedding more than 25% must increase generation protection delay times and/or change set points to achieve coordination with load shedding. For example, Manitoba Hydro and Saskatchewan need to shed more than 30% of the area load to achieve reasonable frequency recovery in their islands. In these areas, the shedding of a higher percentage of load may allow the frequency to drop below 58.2 Hz for longer than 4 seconds, but the subsequent impacts on the hydro generator in these islands are acceptable. Attachment 2 for R4.4, R4.5, R4.6 6. The title for Attachment 2 should clearly qualify that this curve applies for a 25% or less island imbalance. The curves that should be used for UFLS programs associated with imbalance levels greater than 25% (e.g. 30%, 40%, 50%) would be different from the 25% curve. Generator Underfrequency and Overfrequency Attachments 7. The Generation Owner off-nominal frequency coordination requirements and coordination curves should be included in the PRC-006 standard. The generation curves should be applicable for load shedding levels beyond the 25% (e.g. 30%, 40%, 50%). If curves beyond 25% are not include, then the titles of the curves should qualify that they apply for 25% imbalance and include an note regarding coordination with UFLS programs that shed higher than 25% of the island load. The line should extend to 57 Hz (at .3 sec) to 59.5Hz (at 1800 sec). The minimum frequency of 57.0 Hz was chosen because most conventional generation can briefly operate down to 57.0 Hz and large load shedding programs may need to make use of that capability to achieve coordination with these UFLS programs. Volts/Hertz Performance Characteristic 8. The Volts/Hz requirement should be removed. This performance characteristic cannot presently be properly simulated. The voltage regulator V/Hz controls are not presently included in generator exciter/voltage regulator models of the present power system modeling programs that are used for dynamic power system simulation. In addition, the Volts/hertz requirement is not need in this standard. Voltage regulators automatically reduce voltage according to volts per hertz when in the automatic mode. Industry recommendations/standards (IEEE C37.102 or IEEE C37.106, ANSI C50.13-1989, IEEE C57.12.00-2000) already exist that adequately address the volts/Hz issue.
Yes
 
No
Replace the words “reach concurrence with” with “provide UFLS design assessment results to”. Fulfillment of a compliance measure that involves reaching concurrence with another entity is dependent on the other entity and can be outside of the control of the Planning Coordinator. In addition, replace the words “other affected Planning Coordinators” with “other Planning Coordinators that have design assessment responsibilities for islands covered in the design assessment report. The qualification of “other affected Planning Coordinators” is too vague and could be interpreted and categorized differently by various entities and auditors.
No
Consideration should be given to replacing “Transmission Owner” with “UFLS Entity” because the automatic switching of distribution Elements (e.g. capacitor banks) may be more effective and practical UFLS design than restricting the scope of the requirement to just transmission Elements.
No
1. For R11, replace “Each Planning Coordinator, in whose footprint . . . to evaluate” with “When a disturbance event occurs in a Planning Coordinator’s footprint that involves automatic UFLS program operation or frequency excursions should have activated UFLS program operation, and a final disturbance report is required per EOP-004, each Planning Coordinator shall evaluate within one year of the disturbance event:”. 2. Either part of or after R11, there should be a requirement that “Each Planning Coordinator shall provide a preliminary event assessment report to the other Planning Coordinators who must conduct an assessment of the event for review at least 90 days before finalizing the event assessment report. 3. For R13, replace “in whose footprint . . .on the event assessment result” with “that conducts an UFLS design assessment (per R12) for islands where other Planning Coordinators have design assessment responsibilities shall provide a preliminary design assessment report to those Planning Coordinators for review at least 90 days before finalizing the design assessment report. The reference to the event assessment report should be part of R11. The qualification of “event affecting multiple Planning Coordinators” is too vague and could be interpreted and categorized differently by various entities and auditors
Yes
 
Group
Western Area Power Administration
Brandy A. Dunn
Western Area Power Administration - Corp Services Office
 
 
 
 
 
 
No
R2 thru R5 - is specific to under voltage conditions but the "Purpose" of the standard states is for insufficient generation along with insufficient xmsn capacity. Also the Transmission Operator does not establish plans or coordinate for auto load shedding for under voltage conditions - this is a function of Planning R6 and R7 - now the requirements are back to under frequency along with under voltage. R8 - states the Operator shall be capable of implementing load shed adequate for responding to the EM - in most cases there is not enough time to respond manually. Is this referencing if a condition develops slowly enough to have time to respond? Seems like the purpose and requirements should be further defined so that EOP-003 is specifically for BA and Transmission Operations for developing low voltage/frequency conditions with ability/authority to shed load and PRC-006 for Planning defining auto load shed for low voltage/frequency conditions.
 
No
 
 
 
 
 
 
Individual
Scott Berry
Indiana Municipal Power Agency
Yes
 
Yes
 
Yes
 
Yes
 
Yes
IMPA agrees with these actions.
Yes
 
Yes
However, changes need to be coordinated with the tiger team and their changes to EOP-003-1.
Yes
IMPA believes that this draft allows entities who are currently providing UFLS at the transmission level to stay in place and provide this service going forward. IMPA hopes that the Planning Coordinators will establish their UFLS program by using this current UFLS setup prvided by Transmission Owners and not force a financial burden onto Distribution Providers by requiring then to install UFLS equipment. In states such as Indiana and Illinois, UFLS is performed at the transmission level for some entities and includes all the distribution load in the area regardless of size and voltage connection to the BES.
Yes
 
Yes
When looking at generation in the RFC region and by going with generating units that are specified in the current sub requirements of requirement 4, the Planning Coordinators will be capturing 96 PERCENT of the generation in the RFC region in their UFLS program and design assessment (data supplied by RFC). When looking at generation between 69kV and 100kV, only about 2 PERCENT increase is gained in this area by requiring these Generation Owners to report information (this is making the assumption that all these lower voltage units have UFLS relays). One has to question the value of this increase in requiring these generating units to report information when load is not being captured that accurately and the modeling has a certain percent error. In addition, NERC reporting requirements will have to apply to these generating units connected between 69kV and 100 kV which will force the NERC registration of these units. NERC compliance has made the statement on several documented occasions that if a new Generator Owner goes on the NERC registry, then that entity will have to meet ALL the NERC Generator Owner standard requirements in a NERC and FERC audit, NOT just the NERC UFLS standard. This would be a case where a standard drives the NERC Registry and IMPA does not believe that reliability standards should drive and change the NERC Registry.
Yes
 
Yes
 
Yes
 
Yes
 
Individual
Claudiu Cadar
GDS Associates
 
 
 
No
- Standard not entirely clear regarding to whom will apply (see 4.), groups or individual Planning Coordinators within the Regional Entity footprint. - Not sure what is the intent for paragraph 4.3
 
 
 
 
No
- See the answer to question 10. pertaining the classification of generating units / plants
No
- Not sure what is the intent of this classification of generating units >20MVA, generating facilities (two or more units) directly connected to BES >75MVA and generating facilities connected to a common bus to BES >75MVA - Are the requirements for the two categories of facilities larger than 75MVA meant to overcome the differences regarding the point of interconnection? If affirmative 3.3.3, should state “Generating plants / facilities greater than 75MVA (gross aggregate nameplate rating) connected to the BES at a common point of interconnection (sharing a common station bus)”
No
- Requirement R1 is quite unclear. Not sure how the criteria will be developed especially to include the interconnected adjacent sections of the BES. What if one of the adjacent entities does not agree to the criteria? Is that OK because the Planning Coordinator will no longer join groups so is no need to coordinate?
 
No
- Requirement R11. The one year deadline it seem very long. There can be multiple events before assessment is due. - Requirement R12. Same comment regarding the assessment due date.
 
Individual
Joe Springhetti
Wisconsin Electric Power Company (dba We Energies)
Yes
 
Yes
We agree with the Measures as far as the draft standard is currently written, however, see our comments for questions 11, 12, and 13 that would require modifications to requirements R9 & R10 and to M9 & M10.
Yes
We agree with the Violation Severity Levels as far as the draft standard is currently written, however, see our comments for questions 11, 12, and 13 that would require modifications to requirements R9 & R10 and the corresponding Violation Severity Levels.
No
Although we agree that the Planning Coordinator has the wide-area view and technical skills to oversee the design of and ensure the effectiveness of a UFLS program, we are concerned with how this concept will actually play out, especially when a UFLS Entity is within multiple Planning Coordinators’ footprints.
Yes
See comments for question 6 and 7.
Yes
We agree with the expanded scope of the supplemental SAR, however, EOP-003-1 needs further revision to focus this standard solely on manual loadshed. References to the development of both UFLS and UVLS programs need to be removed from EOP-003-1 as PRC-006-1 will cover automatic UFLS programs and a series of other PRC standards already cover automatic UVLS programs. The SDT should delete R2, R4, R7 and M1 from the posted SDT revised draft standard EOP-003-1 as part of supplemental SAR limited scope of revising requirements related to underfrequency loadshedding. In addition, the SDT should give consideration to inserting the word “manual” in front of the words “load shedding” in R3 and R5 in the posted SDT revised draft standard EOP-003-1. The Measures and Violation Severity Level sections would need to be updated accordingly.
No
Although we agree with the intent of the revisions, EOP-003-1 needs further revision to focus this standard solely on manual loadshed. References to the development of both UFLS and UVLS programs need to be removed from EOP-003-1 as PRC-006-1 will cover automatic UFLS programs and a series of other PRC standards already cover automatic UVLS programs. The SDT should delete R2, R4, R7 and M1 from the posted SDT revised draft standard EOP-003-1 as part of supplemental SAR limited scope of revising requirements related to underfrequency loadshedding. In addition, the SDT should give consideration to inserting the word “manual” in front of the words “load shedding” in R3 and R5 in the posted SDT revised draft standard EOP-003-1. The Measures and Violation Severity Level sections would need to be updated accordingly.
Yes
 
Yes
We agree with the concept of using the frequency time performance curves instead of discrete points. However, we would like the SDT to provide additional technical background on the methodology utilized to develop both the underfrequency and overfrequency time performance curves beyond what was discussed in the “Review of Technical Changes to Standard” section in the preface of the “Unofficial Comment Form.”
No
We agree with the concept of using the PRC-024 generator underfrequency and overfrequency tripping curves instead of discrete points. In addition, we agree with the generator size and connection threshold clarification. However, we continue to believe that this standard places a burden on the UFLS Entity to shed additional load to make up for generators which do not conform to the PRC-006/PRC-024 curves. For example, if an independent power producer did not conform with the PRC-006/PRC-024 curves, it places a burden on the UFLS Entity to potentially have to shed additional load, up to the generator’s rating, to make up for the non-conforming independent generator.
Yes
Although we agree with the revision, we disagree with carrying forward the legacy concept of using an entire Regional Entity’s footprint as an island. It is highly unlikely that the entire Regional Entity footprint would become an island. What is the technical justification for the continuation of the legacy concept of studying islands consisting of the entire Regional Entity’s footprint? In addition, similar to the concurrence that the Planning Coordinators need to reach in R5, concurrence needs to be reached between the Planning Coordinator(s) and the UFLS Entity on the UFLS program design and schedule for application. R9 needs to be revised as follows: “The Planning Coordinator(s) and each UFLS entity shall reach concurrence on the UFLS program design and schedule for application in each Planning Coordinator footprint in which the UFLS entity owns assets. Upon concurrence, each UFLS entity shall provide automatic tripping of Load in accordance with the UFLS program design and schedule for application determined by its Planning Coordinator(s) in each Planning Coordinator footprint in which it owns assets.” Measurement M9 needs to be revised to include the concurrence. The Data Retention and Violation Severity Level sections need to be updated accordingly. Similar to the concurrence that the Planning Coordinators need to reach in R5, concurrence needs to be reached between the Planning Coordinator(s) and the Transmission Owner on the automatic switching of Elements in accordance with the UFLS program design and schedule for application. R10 needs to be revised as follows: “The Planning Coordinator(s) and each Transmission Owner shall reach concurrence on the automatic switching of Elements in accordance with the UFLS program design and schedule for application in each Planning Coordinator footprint in which the Transmission Owner owns transmission. Upon concurrence, each Transmission Owner shall provide automatic switching of Elements in accordance with the UFLS program and schedule for application determined by the Planning Coordinator(s) in each Planning Coordinator footprint in which it owns transmission.” Measurement M10 needs to be revised to include the concurrence. The Data Retention and Violation Severity Level sections need to be updated accordingly.
No
Although we agree with the intent of this requirement, similar to the concurrence that the Planning Coordinators need to reach in R5 & R13, concurrence needs to be reached between the Planning Coordinator(s) and the Transmission Owner on the automatic switching of Elements in accordance with the UFLS program design and schedule for application. R10 needs to be revised as follows: “The Planning Coordinator(s) and each Transmission Owner shall reach concurrence on the automatic switching of Elements in accordance with the UFLS program design and schedule for application in each Planning Coordinator footprint in which the Transmission Owner owns transmission. Upon concurrence, each Transmission Owner shall provide automatic switching of Elements in accordance with the UFLS program and schedule for application determined by the Planning Coordinator(s) in each Planning Coordinator footprint in which it owns transmission.” Measurement M10 needs to be revised to include the concurrence. The Data Retention and Violation Severity Level sections need to be updated accordingly. Similar to the concurrence that the Planning Coordinators need to reach in R5 & R13, concurrence needs to be reached between the Planning Coordinator(s) and the UFLS Entity on the UFLS program design and schedule for application. R9 needs to be revised as follows: “The Planning Coordinator(s) and each UFLS entity shall reach concurrence on the UFLS program design and schedule for application in each Planning Coordinator footprint in which the UFLS entity owns assets. Upon concurrence, each UFLS entity shall provide automatic tripping of Load in accordance with the UFLS program design and schedule for application determined by its Planning Coordinator(s) in each Planning Coordinator footprint in which it owns assets.” Measurement M9 needs to be revised to include the concurrence. The Data Retention and Violation Severity Level sections need to be updated accordingly.
No
Although we agree with the intent of these requirements, the assessment required in R11 & R13 should only be completed for significant UFLS events. Similarly, the significant event concept should be applied to the islanding criteria in R1. In fact, the SDT mentions this concept in the “Review of Technical Changes to Standard” section in the preface of the “Unofficial Comment Form.” In the aforementioned section, the SDT uses a 500 MW qualifier which states “…resulting in 500 MW or greater of…” for R11 & R13 but the qualifier was not added to version 3 of the draft standard. Instead of an arbitrary 500 MW qualifier, the SDT should define islands of significance by looking at the transmission interface that feeds the potential island area and what is the IROL (Interconnection Reliability Operating Limit) for that transmission interface. If the amount of load in the island area is below the IROL limit, the island would not be considered as a basis in the UFLS program design and excluded from a UFLS assessment following a UFLS event. This significant event concept based on IROL should be included in the islanding criteria in R1 and the assessment requirements of R11 and R13. Similar to the concurrence that the Planning Coordinators need to reach in R13, concurrence needs to be reached between the Planning Coordinator(s) and the UFLS Entity on the UFLS program design and schedule for application. R9 needs to be revised as follows: “The Planning Coordinator(s) and each UFLS entity shall reach concurrence on the UFLS program design and schedule for application in each Planning Coordinator footprint in which the UFLS entity owns assets. Upon concurrence, each UFLS entity shall provide automatic tripping of Load in accordance with the UFLS program design and schedule for application determined by its Planning Coordinator(s) in each Planning Coordinator footprint in which it owns assets.” Measurement M9 needs to be revised to include the concurrence. The Data Retention and Violation Severity Level sections need to be updated accordingly. Similar to the concurrence that the Planning Coordinators need to reach in R13, concurrence needs to be reached between the Planning Coordinator(s) and the Transmission Owner on the automatic switching of Elements in accordance with the UFLS program design and schedule for application. R10 needs to be revised as follows: “The Planning Coordinator(s) and each Transmission Owner shall reach concurrence on the automatic switching of Elements in accordance with the UFLS program design and schedule for application in each Planning Coordinator footprint in which the Transmission Owner owns transmission. Upon concurrence, each Transmission Owner shall provide automatic switching of Elements in accordance with the UFLS program and schedule for application determined by the Planning Coordinator(s) in each Planning Coordinator footprint in which it owns transmission.” Measurement M10 needs to be revised to include the concurrence. The Data Retention and Violation Severity Level sections need to be updated accordingly.
Yes
 
Group
FirstEnergy
Sam Ciccone
FirstEnergy Corp.
Yes
 
No
Since we do not agree with some of the standard requirements, we therefore do not agree with the measures for some of the requirements as written.
No
Since we do not agree with some of the standard requirements, we therefore do not agree with some of the VSL for the requirements as written.
Yes
 
Yes
While we agree with the inclusion of the EOP-003 in this project, the versioning and requirement language adjustments requires coordination with the proposed revision of EOP-003 that is taking place with the Order 693 Directives work Project 2010-12.
Yes
While we agree with the inclusion of the EOP-003 in this project, the versioning and requirement language adjustments requires coordination with the proposed revision of EOP-003 that is taking place with the Order 693 Directives work Project 2010-12.
Yes
Although we agree with the revisions to EOP-003 with regard to removal of underfrequency load shedding references, we believe the SDT could have improved the standard even further by developing a complete set of measures. There are currently only two measures for eight requirements. Furthermore, since EOP-003-1 is the current approved standard, and this standard would be version 2 (EOP-003-2).
No
We support the applicability section of the standard as asked per this question. However, we do not see any question for general comments and have comments and suggestions regarding the proposed implementation plan for the applicable UFLS entities and Transmission Owners that own Elements identified in the UFLS program. 1. Although we agree that the Planning Coordinator is the appropriate functional entity to develop and implement a UFLS program, we are concerned with the fact that UFLS entities may not know the specifics of their responsibilities until long after this standard is approved. The SDT should consider adjusting the language of the standard to require more transparency and coordination with the UFLS entities during the PC's development of the UFLS program. Also, per the implementation plan, the PC will be given one year to develop its UFLS program. However, the timeframe for the UFLS entity is based on the schedule imposed by the PC. The implementation plan should allow the UFLS entity at least one year (maybe more per capital budget cycles) from the time the PC identifies the UFLS entity in their UFLS program. The UFLS entity will need sufficient lead time in those instances that require purchase of new UFLS equipment that will require long term budget planning for implementation. 2. The UFLS entities are identified in the UFLS program established by the PC. However, it is not clear where the PC is explicitly required to notify and coordinate with the UFLS entity. In Requirement R3 it is implied that the PC will notify and coordinate with the UFLS entity per the phrase "including a schedule for implementation by UFLS entities within its footprint". This requirement needs to be more explicit that the PC will notify the UFLS entity, and the measure for R3 needs to require proof that the PC has done this.
No
We are concerned about the coordination between this UFLS SDT and the GV SDT. It will be difficult to approve and begin implementing the PRC-006-1 standard while the PRC-024-1 standard is still under development and scheduled for approval and implementation at a much later date. For these requirements to be adequately coordinated, the two standards need to be developed, balloted and implemented at the same time. Alternatively, consider adding the following statement in the PRC-006-1 Implementation Plan: "The Effective Date and implementation of this PRC-006-1 standard requires coordination with standard PRC-024-1. Excluding requirement R1, the Effective Date of PRC-006 shall be the later of 1) the completion of the Implementation Plan for PRC-006 or 2) the completion of the Effective Date of the PRC-024-1 standard upon completion of its Implementation Plan."
No
See our concerns in Question 9 about the coordination between this UFLS SDT and the GV SDT.
We defer an opinion on this and leave it to the Planning Coordinators to decide if this requirement is feasible for them to implement.
No
FE questions the need for this requirement and the Applicability Section item 4.3. FE asks that the SDT provide some examples of the reliability need related to frequency control for this requirement. If high voltage and automatic capacitor bank switching is the issue we don't believe that rises to a need as a reliability requirement within a UFLS standard. Voltage control should remain a separate issue from controlling frequency that this standard aims to address. Load shedding associated with UFLS is just one of many reasons why proper voltage control - through automatic Element switching of a capacitor bank - would be needed for the transmission system. If there are other technical reasons for this requirement please clarify.
We defer an opinion on this and leave it to the Planning Coordinators to decide if this requirement is feasible for them to implement.
Yes
 
Individual
John O'Connor
Progress Energy - Carolinas
Yes
We agree with proposed VRFs. However, we would recommend the VRF Tool be used to validate these.
No
For M3, it is unclear what is meant by the phrase “including the criteria itself.” Since the criteria is specified in R3, we recommend this phrase be deleted from the measure. For M5, this measure should only apply to Planning Coordinators (PCs) who are part of a joint island, but it is written such that it appears to apply to all PCs. We recommend rewording M5 to “Each Planning Coordinator shall have dated evidence…that it reached concurrence with the other affected PCs on design assessment results for any islands in accordance with Requirement R5 and identifies the affected PCs.” We also recommend that R5 be reworded to “Each PC shall reach concurrence with all other affected PCs on UFLS design assessment results before design assessment completion for any islands identified by that PC which include a portion of that PC's footprint along with another PCs footprint.”
No
For R4, the VSLs should include a consideration of the timeliness of the completion of the required study (e.g. lower VSL for 3 months late, Moderate for 3-6 months late, etc.). For the R11 VSLs, we recommend that the time ranges for the VSLs be expanded to allow more than one month between Low, Moderate, High and Severe. We would suggest revising to Moderate 12-14 months, High 14-16 months, and Severe greater than 16 months past the 12 month requirement.
No
Requirements R5 and R13 require Planning Coordinators (PCs) from two or more areas to agree on assessment results. However, no process is provided in the event that the PCs cannot agree. One party may have larger margin requirements or a different methodology and these differences may not be reconcilable. Therefore, it is possible that multiple PCs could be prevented from meeting the agreement requirement through no fault of their own. There needs to be a process for resolving this. We recommend that R5 include “If concurrence cannot be reached, an individual PC in the applicable island may demonstrate that its UFLS scheme meets the requirements by performing dynamic simulations that apply that PC’s individual scheme to the entire island.” Also, we recommend that R13 be deleted since R11 would effectively require these actions for multi-PC islands.
Yes
 
Yes
 
Yes
 
Yes
We recommend that R3 be revised to specifically require the Planning Coordinator to notify the “UFLS entities” in their PC area that they are part of the PC’s UFLS program.
Yes
The curves added as Attachments 1 and 2 are excellent. However, it would be helpful if a footnote to the curves provided the values of the “transition points” or breakpoints of the curves. For example on Attachment 1, there appears to be transition point at 60 seconds/58.85 Hz, but it is difficult to read exactly.
Yes
We agree with respect to the Planning Coordinator simulation requirements for modeling as stated in R4. However, the UFLS standard has no requirement for the Generator Owners to provide this information. We have been told that this might be included in PRC-024 (currently under development). This should be a condition for approval of PRC-006. Additionally, the Generator Owners should be required to notify the PC of any Manual (i.e. operator actions) that would result in a trip above/below the specified generator curves of Attachments 1 and 2. It is recognized that manual operator actions would typically be later than the approximately 60 seconds or less simulation times that a PC would use. However, this information regarding manual trips would be necessary for appropriate planning.
No
See above comments to Questions #2 and #4.
Yes
It is not clear what would be included in automatic switching. Illustrative examples would be helpful to clarify what is meant (e.g. automatic switching out of a capacitor bank to avoid overvoltage when designed as part of the UFLS scheme). R10 refers to “Elements” and M10 refers to “Facilities”. Revise to make consistent. In both R9 and R10, replace the word “provide” with “implement.”
No
As per our comment to Question #4, we recommend R13 be deleted. The 500 MW limitation discussed in the background section of the comment form should be included in R11. There is no need to require assessments for smaller islanding events.
Yes
 
Group
Southern Company Transmission
JT Wood
Southern Company
Yes
We recommend that the VRF Tool be used to validate the proposed VRFs.
No
M3: It is unclear what action is intended by the phrase "including the criteria itself." Since the criteria is specified in R3, it is recommend that it be deleted. M5 and R5: This should only apply to PCs who are a part of the joint island, while the way it is currently worded it appears to apply to every PC. Recommend that the wording in M5 be changed to: "Each Planning Coordinator shall have dated evidence such as memorandums, letters, or other dated documentation that it reached concurrence with the other affected Planning Coordinators on design assessment results for any identified islands in accordance with Requirement R5 and identifies the affected Planning Coordinators." Recommend that the wording in R5 be changed to: "Each Planning Coordinator shall reach concurrence with all other affected Planning Coordinators on UFLS design assessment results before design assessment completion for any islands identified by that Planning Coordinator which include a portion of its footprint along with portions of another PC(s) footprint."
No
The Lower VSL for R11 needs work. It appears to simply repeat the requirement rather than stating a violation. Recommend that the time ranges for the VSLs addressing being late with the assestment should be expanded to Moderate 12-14 months, High 14-16 months, and Severe greater than 16 months. Revise the High and Severe VSL that contain the phrase "shall conduct and document" to read: "conducted and documented." The R4 VSLs should include a consideration of the timeliness of the completion of the study (e.g. lower VSL for 3 months late, Moderate for 3 to 6 months, etc.).
No
R5 and R13 seem very problematic. The standard requires that both or all the entities agree. One entity might have larger margin requirements or a different methodology compared to another entity. These differences might not be reconcilable. We do not believe that a standard can require that one PC change its methods because a different PC does not agree with its methods, or agree that another method (any method) is acceptable that it finds a problem with. There at least needs to be a process in the event that two companies cannot agree. We recommend that the following language be added to R5: “If concurrence cannot be reached, an individual Planning Coordinator in that island can demonstrate that its UFLS scheme meets the requirements by performing dynamic simulations that apply its UFLS scheme on the entire island.” We recommend that R13 be eliminated since it is covered by R11.
 
Yes
 
Yes
 
Yes
We recommend that R3 be revised to require the PC to specifically notify the “UFLS Entities” in their PC area that are part of the PC’s UFLS program.
Yes
 
Yes
 
No
see above comment to questions #2 and #4.
Yes
It is not clear what is included in automatic switching. Illustrative examples would be helpful to clarify what is meant (e.g. automatic switching of a capacitor to avoid overvoltage). R10 refers to “Elements” and M10 refers to “Facilities.” In both R9 and R10, replace the word “provide” with “implement.”
No
As noted in our response to question #4 above, we recommend elimination of R13. The 500 MW limitation discussed in the background section should be included in R11. There is no need to evaluate smaller islanding events.
Yes
 
Individual
Greg Rowland
Duke Energy
Yes
However we have identified an issue with R5 and R13 requiring that Planning Coordinators “reach concurrence” which brings their VRFs into question. This is discussed further in our comments below.
No
M3 – it is unclear what is meant by the phrase “including the criteria itself”. Suggest deleting the phrase. Also, requirements R5 and R13 (and hence their Measures and VSLs) are problematic, since they require that Planning Coordinators shall “reach concurrence” with all other affected Planning Coordinators, which may not always be possible. The requirements need to provide for that situation.
No
See comment to question #2 above.
Yes
Yes, except for the issue on “reaching concurrence” identified in our response to question #2 above (R5 and R13).
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
No
See comments above on questions #2 and #4.
No
We question whether/how this requirement would apply to a Transmission Owner who has UFLS on distribution circuits. It’s unclear to us how this would be determined by the Planning Coordinator.
No
R11 and R12 are okay, but R13 contains the problematic requirement to “reach concurrence”, as discussed in our responses to questions #2 and #4 above. Perhaps R13 could be revised to require affected Planning Coordinators to share event assessment results and respond to technical questions/comments within a prescribed time period.
 
Group
MRO’s NERC Standards Review Subcommittee (NSRS)
Joseph DePoorter
Midwest Reliability Organization
No
The VRFs for R3, R4, R9, and R10 should be reduced from “High” to “Medium” for several reasons. [1] Automatic UFLS programs are system preservation measures of last resort that may help the BES recovery if the primary system preservation measures are insufficient. So, the risk to the system reliability is low because primary measures will normally restore the system even if some UFLS requirements are not completely fulfilled. [2] System events that would activate automatic underfrequency load shedding have been very rare. So, the risk to system reliability is low because events of unacceptable underfrequency rarely occur even if the sum of the UFLS requirements not completely fulfilled. [3] Automatic UFLS programs can only be designed to help preserve the system for a wide range of, but not all, possible system conditions. So, the risk to system reliability is low because UFLS programs may help for many system condtions, even if some of the UFLS requirements are not completely fulfilled. [4] For R4, the performance of the UFLS program and the characteristics of the associated islands change only slightly and gradually over many years. So, the risk to system reliability would not change dramatically if conducting or documenting of a UFLS design assessment was delayed by several years.
No
Suggest that the measures be modified to reflect any changes made to standards Requirements per the comments made to questions Q4 through Q13. M10 – Replace “automatic switching of Facilities” with “automatic switching of Elements” to be consistent with the associated Requirement R10.
No
Most of the VSLs are okay. However, the VSLs for R5 and R13 depend on reaching “concurrence” with other entities, which is not a valid basis for measuring compliance. If the concurrence requirement is not revised as suggested below, then we propose that the VSL levels be reduced.
Yes
Although THE NSRS agrees with changing the applicability of the requirements from groups of Planning Coordinators to each Planning Coordinator, the present wording in R2.3 says that for a PC with a part of its footprint in more than one region, “each of those Regional Entity footprints shall be identified as an island.” We propose that the wording be revised to require a PC with part of its footprint in more than one region to identify only those appropriate parts of its area that are in islands, not the entire Registered Entity footprint where it may be present.
 
No
We propose that the scope of the SAR be revised to call for removing all of the automatic UFLS requirements from EOP-003-1 and moving them to PRC-006-1 standard because no automatic load shedding system requirements should be in the EOP standards. We also note that a separate SAR should be initiated to call for the removal of all the automatic UVLS requirements from EOP-003-1 and moving them to a new PRC standard for the same reason.
No
In line with the comments for Question 6: R2 - remove this requirement because it refers to automatic load shedding plans and let the automatic requirements be covered by PRC-006-1 and a new PRC standard. R3 – Recommend R3 be rewritten to read: Each Transmission Operator and Balancing Authority shall provide manual load shedding plans to adjacent interconnected Transmission Operators and Balancing Authorities.
Yes
 
No
1. In R3, simply say that the “program shall shed at least 25% of island load” and avoid use of the formula. If the formula is retained, then we suggest that it be changed to the more common industry nomenclature of “imbalance = (load-generation)/generation.” 2. In R4, we interpret that the Equivalent Inertia Analysis is a valid dynamic simulation methodology for certain aspects of UFLS assessments. This is a methodology that is often recommended in relay application guides and other technical references. Please clarify that this type of dynamic analysis would be accepted toward compliance with the “through dynamic simulation” portion of this requirement. For Attachment 1 (R4.1, R4.2 & R4.3) and Attachment 2 (R4.4, R4.5 & R4.6) 3. Attachment 1 and 2 include transient frequency performance curves for at least 30%, 40% and 50% island imbalance. Otherwise, revise the titles for Attachments 1 and 2 to clearly qualify that the transient frequency performance curves apply for a 25% or less island imbalance and that programs which are larger than this minimum load shedding requirement do not have to meet this criteria when overloads are in excess of 25%. In addition, UFLS programs that are designed for appropriate performance under imbalance conditions above 25% will not have the same performance curves as programs that are designed for imbalance conditions of 25% or less. 4. If item #3 is not adopted, then the Under Frequency Performance Characteristic line in Attachment 1 should be extended from the knee at approximately 58.9 Hz (for 60 seconds) to 59.3 Hz or 59.5 Hz (for approximately 500 sec). The purpose is to define a single line of constant slope and to get rid of the arbitrary knee in the characteristic curve which serves no reliability purpose. The reason for this change is that the worst case frequency recovery time for frequencies between 58.7 Hz and 59.5 Hz may occur for imbalance conditions significantly less than 25% where the governor response prevents the load shedding blocks from picking up and where frequency recovery times are a function of governor response and system inertia. Likewise, it makes sense to extend this line below 58 Hz to at least as low a frequency as is covered by the generation protection curve. 5. Add a note to Attachment 1 that states, "Larger size UFLS programs (e.g., 40%) may require less restrictive (lower) underfrequency (as well as and/or longer time delays) due to island generation and protection characteristics. UFLS programs shedding more than 25% must also increase generation protection delay times and/or change set points to achieve coordination with load shedding. For example, Manitoba Hydro and Saskatchewan need to shed more than 30% of the area load to achieve reasonable frequency recovery in their islands. In these areas, the shedding of a higher percentage of load may allow the frequency to drop below 58.2 Hz for longer than 4 seconds, but the subsequent impacts on the hydro generator in these islands are acceptable. Generator Underfrequency and Overfrequency Coordination Attachments 6. The Generation Owner off-nominal frequency coordination requirements and coordination curves should be included only in the PRC-006 standard and not the PRC-024 standard. The generator coordination curves relate directly to the PRC-006 assessment requirements and the PRC-006 curves will be duplicative of, and possibly contradictory to, the curves in the PRC-024 standard if they are finally approved and then changed in the future. 7. The generation coordination curves need to be appropriate for the different types of UFLS programs (e.g. 25%, 30%, 40%, 50%, etc.) that have, or will be, designed and implemented for different islands. Generation coordination curves for 25% UFLS programs will not be the same for other (e.g. 30%, 40%, 50%) UFLS programs. It can be demonstrated that as the size of the load shedding program is increased, the generation protection settings have to be modified accordingly to achieve the coordination objectives. UFLS programs that are designed for imbalances greater the 25% inherently require lower minimum frequencies and longer frequency recovery times 8. If item #7 above is not adopted, then revise the titles for generation coordination curves to clearly qualify that they apply for a 0% to 25% island imbalance and that programs which are larger than this minimum load shedding requirement do not have to meet this criteria when overloads are in excess of 25%. The generation protection line should extend to 57 Hz (at .3 sec) to 59.5Hz (at 1800 sec). The minimum frequency of 57.0 Hz was chosen because most conventional generation can briefly operate down to 57.0 Hz and large load shedding programs may need to make use of that capability to achieve coordination with these UFLS programs. 9. We are aware of the technical basis for the generator Under Frequency protection setting, but not aware of the technical basis for the presently proposed generation coordination curves in PRC-006 or PRC-024. We suggest that the SDT provide the industry with the technical basis for the generation coordination curves. We are concerned that the curves allow enough time for load shedding to operate under “worst case conditions”, and as much time as possible needs to be given for frequencies close to 60 Hz. We are also concerned that for actual UFLS events system frequency recovery may stall below 59.5 Hz for a long time while operators try to deal with event with manual shedding of load. Volts/Hertz Performance Characteristic 10. The Volts/hertz requirement is not needed in this standard and should be removed for several reasons: [1] Voltage regulators automatically reduce voltage according to volts per hertz when in the automatic mode so they self protect. Industry recommendations/standards (IEEE C37.102 or IEEE C37.106, ANSI C50.13-1989, IEEE C57.12.00-2000) already exist that adequately address the volts/Hz issue. [2] If voltage regulators are in automatic, then the 110% volts/Hz limit becomes active between 57.2 Hz and 51.8 Hz assuming the voltage regulator holds terminal voltage within the allowed 1.05 p.u. to 0.95 pu range. [3] Units with voltage regulators in manual will just trip when volts per Hertz protection picks up. However, units are normally in the automatic control mode per NERC Standards. [4] It appears this requirement is appropriate for programs which may experience frequencies below 57.2 Hz, but few, if any, programs are expected to be designed for frequencies that are this low. [5] Even if UFLS programs are designed for frequencies below 57.2 Hz, this performance characteristic cannot presently be properly simulated in stability cases as the voltage regulator V/Hz controls are not presently included in generator exciter/voltage regulator models of the present power system modeling programs that are used for dynamic power system simulation
Yes
 
No
Replace the words “reach concurrence with” with “provide UFLS design assessment results to”. Fulfillment of a compliance measure that involves reaching concurrence with another entity is dependent on the other entity and can be outside of the control of the Planning Coordinator. In addition, replace the words “other affected Planning Coordinators” with “other Planning Coordinators that have design assessment responsibilities for islands covered in the design assessment report. The qualification of “other affected Planning Coordinators” is too vague and could be interpreted and categorized differently by various entities and auditors.
No
The NSRS basically agrees with the concept that owners of automatic switching elements provide control in accordance with the UFLS program requirements. Therefore, [1] consideration should be given to replacing “Transmission Owner” with “UFLS entity” because the automatic switching of distribution Elements (e.g. capacitor banks) may be more effective and practical in UFLS program design than restricting the scope of the requirement to just transmission Elements.[2] And consider replacing “UFLS program” with “UFLS program requirements”.
No
1. For R11, replace “Each Planning Coordinator, in whose footprint . . . to evaluate” with “When a disturbance event occurs in a Planning Coordinator’s footprint that involves automatic UFLS program operation or frequency excursions that should have activated UFLS program operation, and a final disturbance report is required per EOP-004, each Planning Coordinator shall evaluate within one year of the disturbance event:”. 2. We have concerns about specifying that the evaluation must be complete within one year we know that some historical studies of events that included UFLS took longer than one year [e.g., three years] to complete. Therefore, we would prefer a more flexible wording, a longer time frame to be used in this requirement. Perhaps the requirement could stipulate that the evaluation must begin within 6 months and be completed within the schedule set by the investigative team. 3. For R13, replace “in whose footprint . . .on the event assessment result” with “that conducts an UFLS design assessment (per R12) for islands where other Planning Coordinators have design assessment responsibilities shall provide a design assessment report to those Planning Coordinators.” The reference to the event assessment report should be part of R11. The qualification of “event affecting multiple Planning Coordinators” is too vague and could be interpreted and categorized differently by various entities and auditors. 4. R11.2, change the wording to replace “effectiveness of the UFLS program” with “conformance with UFLS program design”. Because no UFLS program can be designed to be effective for all possible contingency scenarios but should be effective for the contingency scenarios for which it was designed.
Yes
 
Group
ReliabilityFirst Engineering Staff
Art Buanno
ReliabilityFirst Corp.
Yes
 
Yes
 
Yes
 
Yes
 
No response seems applicable.
Yes
 
Yes
Yes, the revisions that were made are appropriate. However, EOP-003 will require further substantial revisions as many of the requirements are still inappropriately assigned to the TOP such as establishing automatic undervoltage load shedding plans (R2).
Yes
 
No
1. It is not clear how the PC is supposed to enforce performance characteristic 3.3. Part 3.3 is written based on general over-excitation limits for generators and transformers. However, entities should already have over-excitation protection on critical equipment. Isn’t the owner obligated to protect its equipment? Also, V/Hz at a bus is not a standard output of dynamic stability programs making it difficult to ensure compliance to part 3.3. It would be more useful if part 3.3 was expressed in terms that are commonly available such as voltage. Additionally, the meaningful per unit voltage is the machine or equipment base and the results would need to be scaled from the system base voltages. 2. The reliance on curves in Attachments 1 and 2 is imprecise. The frequency and time coordinates of each change in slope should be given so that entities do not need to interpret it themselves. 3. The standard relies too heavily on the possible implementation of proposed standard PRC-024. 4. The proposed PRC-006-1 UFLS standard and companion PRC-024 establish tightly defined performance characteristics which at best will just barely work for 30% UFLS programs using 3 steps of 10% load shedding. More precisely, it works for a 30% UFLS program for a range of conditions, but not for all of the conditions that can exist or are expected to exist in various portions of ReliabilityFirst over the next five years. Thus, ReliabilityFirst staff believes that these performance characteristics coupled with declining governor response and declining equivalent inertia in the Eastern Interconnection, will encourage a redesign of one or both of the existing 30% UFLS programs within ReliabilityFirst.
No
It is not clear how the PC will determine which generating units are non-conforming as there is no requirement for the GO to provide this information in this standard. In a best case, it relies on the adoption of proposed standard PRC-024.
Yes
 
Yes
 
Yes
 
Yes
 
Group
Pepco Holdings, Inc. - Affiliates
Richard kafka
Pepco Holdings. Inc.
No
See response to question 7. PHI does not concur with the requirements as written.
No
We do not concur with the requirements as written
No
We do not concur with the requirements as written, so this activity is premature.
No
The SDT has essentially defined groups by requiring concurrence.
Yes
 
Yes
 
No
R2.3 appears to require a PC that is involved in more than one region to have an "islanding program" for its footprint in each region. What if the PC is PJM and there is a sliver a region outside RFC. Do we really need a program for the sliver? This requirement assumes without justification that RE boundaries and PC boundaries define potential islands. R4 - What is a "design assessment"? Why not just require "an assessment every five years"? Why all the extra words like "design assessment"? "conduct and document"? through dynamic simulations? R5 requires concurrence among PCs. My view is that a requirement must be to one and only one functional entity. More than one entity causes questions as to who is non-compliant when things go awry. In R5 who is non-compliant if a peer PC does not concur? R6 Why not just require a database for UFSL data? Why must the requirement include the editorial requirement "for use in Event Analysis and assessments of UFLS program" Does that mean I MUST use the UFLS database for Event Analysis? Does it mean I can't use the data for other activities? R8 is curious to me. It stipulates that the data is provided "to support the database". I ask, isn't the data being required to support the concept that the UFLS program is up-to-date and operational? For both R6 and R8, the issue is editorial explanations in addition to the actual requirement. R12 seems to say that PC whose assessment shows a problem, that PC shall conduct an assessment (again?). The requirement then goes on to mandate the PC "consider" the deficiencies. I know what they want to say but this requirement doesn't say it to me. Can you imagine proving you "considered the deficiencies"?
Yes
 
Yes
 
Yes
 
No
It is difficult to see how this change corrected the described problem.
Yes
 
Yes
 
Yes
 
Individual
Dan Rochester
IESO
No
If the Planning Coordinator does not develop and document criteria, how will other Requirements be satisfied? For this reason, the VRF for R1 should be higher.
No
The measures that refer to Requirements with subrequirements (e.g. R2, R3, and R4) should be more consistent. All of the corresponding Measures (e.g. M2 and M4) should include the final phrase: “including the criteria itself” or none should include this phrase.
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
No
Generator owners are not included in the Applicability Section of this standard. We understand from the SDT’s responses to the last posting that there is a separate project for generator requirements that would obligate them to provide the required information to the Planning Coordinators with which to design the underfrequency load shedding program. Absent that standard, a Generator Owner has no obligation to provide the necessary data to the Planning Coordinators which can result in the Planning Coordinator failing to meet the PRC-006-1 standard. We therefore request that Generator Owner be included in the Applicability Section and a requirement for it to provide the needed information to the Planning Coordinator be added, or balloting of standard PRC-006-1 be deferred until such a requirement in that other standard is ready for balloting. The reason for including Transmission Owners in Section A 4.3 after they have been identified in Section A 4.2 is unclear or not needed.
No
If the overfrequency characteristics are retained, it would be better to combine Attachment 1 and Attachment 2 into one curve. The curves without some explanation may not be consistently interpreted. Should the level line at the shortest times (e.g. < 2 s) and vertical line at the longest time (e.g. > 60s) for the Performance Characteristic be interpreted to mean UFLS tripping is permitted without delay below 58.0 Hz and is not permitted above 59.3 Hz?
No
The SDT should clarify the characteristics define where the generators are not permitted to trip rather than define where generators must trip. Correspondingly, it should be clarified for loads, the requirement defines the outer perimeter where UFLS loads must be tripped rather than to define where UFLS loads trip. The phrase; “directly connected to the BES” could be problematic. In the IESO-controlled grid most generators are connected to transmission system with a main output transformer. At many large generating stations, the low voltage bus of these MOTs where the generator is directly connected is not part of the BES while the high voltage bus is part of the BES. A restrictive interpretation of the present wording of the standard would limit applicability to only generating units captured under §R3.3.3, What interpretation of “directly connected” was intended by the SDT? Elements of this continent-wide standard are viewed by the IESO as a means to improve reliability not as a justification to weaken existing good practices. Does the STD support retaining existing more stringent standards (e.g. lower underfrequency thresholds and higher overfrequency thresholds or both) for generating units at the Regional or Planning Coordinator level? For example, the IESO-controlled grid mandate generating units > 10 MW and generating facilities > 50 MW directly connected to the IESO-controlled grid to have generator protection set at a level such that they do not trip over the NPCC criteria for generator underfrequency curve. We need to seek the SDTs view on whether these conditions are sufficient to satisfy the intent of the PRC-006 standard. The response of the SDT to the earlier question (see below) concerning the need for overfrequency settings as part of this standard was not satisfactory as new requirements should have a strong motivation. Our Area experienced frequency excursions above those proposed in this standard without material adverse effects. Generation trips at these frequency levels in 2003 would have been inconsistent with the purpose of providing last resort system preservation measures. What are these referenced withstand capabilities and are they applicable to all types of units? What evidence is known to the SDT that units experience a significant loss of life due to the events on August 14, 2003 now that more than six years has passed? Why does the SDT believe overfrequency thresholds are necessary to fulfill the Purpose of this standard? [Response: Thank you for your comments. The SDT has developed the overfrequency characteristic in Requirement R6.3 to coordinate with the overfrequency trip setting limits proposed in PRC-024. The trip setting limits were developed by the Generator Verification SDT based on the withstand capabilities of generating units. The concern with operation of generating units at off-nominal frequency is the cumulative fatigue effect, so it is possible that generating units experienced significant loss of life on August 14, 2003 even if the adverse effects were not readily observable immediately after this event.]
No
The requirement to reach concurrence is outside of the capability of any single Planning Coordinator as concurrence requires at least two Planning Coordinators. The SDT should consider reformulating this requirement in terms of the actions it believes each Planning Coordinator must perform to reach concurrence with its fellow Planning Coordinators.
No
The STD may wish to consider reworking R10 in a format that matches changes to applicability. Within the IESO footprint, low voltage capacitors may be switched as part of the ULFS program. In some cases, these capacitors would below to Distribution Providers rather than Transmission Owners. “Each UFLS entity shall provide automatic switching of Elements in accordance with the UFLS program and schedule for application determined by the Planning Coordinator(s) in each Planning Coordinator footprint.”
No
Small islands and frequency excursions below the initializing set points can result from recognized contingencies. In some cases, the island formed will be so small as to provide no meaningful evaluation for UFLS program effectiveness. Some additional guidance from the SDT is needed to define the nature of events that are intended to trigger an evaluation under R11.
Yes
 
Group
Tri-State Generation & Transmission Assoc.
Bill Middaugh
Bill Middaugh
No
Comments: Generally, our primary concern is that the requirements should not apply to individual Planning Coordinators, so it is difficult to agree with any proposed Violation Risk Factors (VRF). The reliability basis for R1 and R2 is not clear and we would recommend eliminating those requirements along with their VFRs. We believe the use of Transmission Owner in R10 is redundant with R9 and “switching of elements” should be merged into R9 and R10 can be eliminated. The five-year assessment in requirement R4 seems like a higher VRF than necessary and Medium would be adequate.
No
Comments: The measures are vague and not performance based leaving much up to interpretation. Measures should contain specific targets or specifications that clarify how an entity will be audited and measured for compliance. These measures merely repeat the requirements and do not provide any useful guidance beyond what is specified in the requirement itself.
No
Comments: We believe that individual Planning Coordinators are not the appropriate entities to be responsible for determining criteria for areas that may form islands, for identifying the islands, for developing the UFLS program, for periodic assessments, for maintaining databases, or for assessing events. Further, Planning Coordinator footprints are neither defined nor is there any guidance on how they should be established. Every VSL that refers to a PC footprint should be clarified. What is meant by “annually maintain” is neither clear nor defined. The VSL for R6 should be re-written. The increment size between VSLs seems arbitrarily small in R9 and R10. Is there a reliability basis for choosing 5%?
No
Comments: Individual Planning Coordinators are not the entities to determine how islands should be formed, unless the Regional Assurer is required to become the only remaining Planning Coordinators, which would be acceptable. The current registration by numerous entities as Planning Coordinators does not lend itself to a comprehensive individual island formation methodology. All Planning Coordinators within an interconnection should be required to collaboratively develop an Interconnection Coordinated UFLS Plan. UFLS works on interconnection basis not on PC footprint basis. We believe that the Regional Assurer will be better able to manage UFLS programs to the extent that the standard clearly lays out what must be accomplished. The primary purpose of any UFLS program is to mitigate the need to form islands by balancing total system loads and resources. It is only a secondary function to balance the loads and resources after the islands have been formed. It appears the Drafting Team focused on the islanding events rather than assuring the interconnection integrity is maintained. Frequency is an interconnection issue not an individual island issue and therefore not driven by an individual PC but by a coordination of PCs efforts within the interconnection. Again, we believe that the Regional Assurer will be better able to manage UFLS programs to the extent that the standard clearly lays out what must be accomplished We strongly believe that this should remain the responsibility of the Regional Assurer (RA), which is the agent(s) for overall coordination within the interconnection or sub-area. For example in the WECC, the RA recognizes the following sub-area groups for UFLS coordination within the Interconnection: Southern Islanding Load Tripping, Northwest Power Pool UFLS Group and the WECC Off Nominal Frequency Load and Restoration Plan. Without the RA assuring coordination of the sub-area groups, PCs could randomly or arbitrarily form sub-area groups whose plans do not coordinate or address the interconnection reliability needs.
 
Yes
 
No
Comments: The revisions are adequate for the most part, but Requirement R4 needs to specify that only undervoltage load shedding is being addressed. There is also a concern that EOP-003-2 is currently being balloted based on changes made as a part of the Order 693 Directives. The two versions are not compatible.
No
Comments: We believe that “ownership” should be removed from the criteria because it may be different from the operating or controlling entity and both entities cannot be responsible. Load Serving Entities should also be included as a “possible” UFLS entity Some large interruptible customers outside of DP or TO could be allowed to own UFLS devices. This should remain the responsibility of the Regional Assurer (RA), which is the agent(s) for overall coordination within the interconnection or sub-area. For example in the WECC, the RA recognizes the following sub-area groups for UFLS coordination within the Interconnection: Southern Islanding Load Tripping, Northwest Power Pool UFLS Group and the WECC Off Nominal Frequency Load and Restoration Plan. Without the RA assuring coordination of the sub-area groups, PCs could randomly or arbitrarily form sub-area groups whose plans do not coordinate nor address the interconnection reliability needs.
No
Each interconnection should establish discrete set points based upon stability and dynamic analysis. From discrete set points one can establish criteria which are measurable and performance based for the applicable entities. The existing analysis tools available are unable to model continuous time/frequency curves and therefore specific measurements for all entities cannot be defined leaving the performance at the discretion of the PC. Furthermore, the Standard needs to be very explicit that the curves are interconnection performance curves and not specific protective relay set points. It is recommended to combine Attachment 1 and Attachment 2 (which contain discrete set points) into a single graph, making frequency the abscissa, and requiring simulations to maintain frequencies inside the resulting envelope. R3.3. While the concern for loss of additional generation units because of their V/Hz protection schemes is understood, the bases for the 1.18pu and 1.1pu values are not evident and may not be technically supportable when compared against actual protection settings or allowable post-contingency voltage bands. Further, V/Hz protection settings vary across the system and it is unlikely adherence to this requirement will impact reliability. It will only increase dynamic analysis requirements. We recommend removing R3.3.
No
Comments: Underfrequency is an issue of load and generation balance. It does not make sense to make the distinction of whether or not a generator or generating facilities directly connect to the BES. The loss of sizable generation has the same impact on frequency regardless of what voltage it was connected at. The thresholds used in the standards are registration thresholds for the GO/GOP function. There is nothing that would prohibit a PC, TO or TOP from establishing interconnection requirements for smaller generators that require compliance with an UFLS program if it was important to reliable BES operation
No
Comments: Elimination of Requirement R4 is acceptable; however, we believe that individual Planning Coordinators are not the entities to determine how islands should be formed. The current registration by numerous entities as Planning Coordinators does not lend itself to a comprehensive individual island formation methodology. R2.3 seems to require each Planning Coordinator to ultimately divide into multiple islands or separate its transmission system from all other transmission systems as its own island. Part of the purpose of the UFLS program should be to mitigate the need to form islands by balancing total system loads and resources. It is an additional function to balance the loads and resources after the islands have been formed. We recommend eliminating R2.
No
Comments: Since “UFLS entity” already includes Transmission Owners, requirement R10 is unnecessary and “automatic switching of Elements” ought to be combined into R9 from R10 and then R10 can be deleted. UFLS programs should be developed by the Reliability Assurer, not individual Planning Coordinators.
Yes
Comments: The concept is correct but we believe an individual Planning Coordinator is the wrong entity to assess the operation and revise it. There is no clear jurisdiction for a PC. This should remain the responsibility of the Regional Assurer (RA), which is the agent(s) for overall coordination within the interconnection or sub-area. Why is “of UFLS actuated loss of load occurs” included in R13 but not in R11? It does not seem to add any information but does seem to unnecessarily complicate the requirement. This again seems like an argument for having the Regional Assurer involved because concurrence between Planning Coordinators is required. The language is unclear in R13 and should be re-written.
No
Comments: The standard should adequately recognize the performance characteristics of different type of generation and a variance should not be required. Faster acting and greater inertia systems should be allowed the operating margins appropriate to their systems. Real differences exist between interconnections. The standard and its performance requirements should reflect this fact. This would allow for the uniqueness of each interconnection to be addressed similar to Hydro Quebec’s variance.
Individual
Darcy O'Connell
The California ISO
No
Cannot support approval until the requirements are closer to being finalized.
No
Cannot support approval until the requirements are closer to being finalized.
No
Cannot support approval until the requirements are closer to being finalized.
 
 
 
 
No
1) Applicability of the proposed Standard PRC-006-1 should also apply to Load Serving Entities (LSEs) for underfrequency load shedding. 2) Applicability of the proposed Standard PRC-006-1 should also apply to Generator Owners since GOs would need to be involved for overfrequency generation tripping. 3) Applicability of the proposed Standard PRC-006-1 should also apply to the Reliability Assurer/Regional Reliability Organization (RRO). (WECC in our case). 4) The Reliability Assurer/Regional Reliability Organization (RRO) should be the entity that coordinates the UFLS programs.
 
 
 
 
 
Yes
We request a WECC Regional variance for WECC to use its own set-points that are applicable to WECC members. (similar to what Hydro Quebec has done.)
Individual
Terry Harbour
MidAmerican Energy
No
The VRFs for R3, R4, R9, and R10 should be reduced from “High” to “Medium” for several reasons. System events that would activate automatic underfrequency load shedding have been very rare and automatic UFLS is a system preservation measure of last resort, not primary system preservation measure. For R4 in particular, the performance of the UFLS program and the associated islands do not change rapidly or dramatically to warrant a “High” VRF for delayed conducting or documentation of a UFLS design assessment
No
Ensure that measures correctly reflect modified requirement changes. In addition there are concerns with the addition of requirements and measurements to reach concurrence. This potentially subjects an entity to non-compliance based on events beyond that entity’s control such as a problematic neighbor that refuses to reach concurrence. This concpept should be removed and replaced with a requirement to distribute the results. Examples include M5 - As noted in the comments below for R5, replace the words “reached concurrence with” with “provided a UFLS design assessment report to”. Fulfillment of a compliance measure that involves reaching concurrence with another entity is dependent on the other entity and can be outside of the control of the Planning Coordinator. In addition, replace the words “other affected Planning Coordinators” with “other Planning Coordinators that have design assessment responsibilities for islands covered in the design assessment report. The qualification of “other affected Planning Coordinators” is too vague and could be interpreted and categorized differently by various entities and auditors. M7 – As noted in the comments below for R7, replace “within their Interconnection”, with “that have design assessment responsibilities within the islands covered by the UFLS database”. Planning Coordinators that are within the same Interconnection, but are not within any islands covered by another Planning Coordinators UFLS database, would not need to receive the UFLS information. M10 – Replace “automatic switching of Facilities” with “automatic switching of Elements” to be consistent with the associated Requirement R10
Yes
 
Yes
 
No
The SAR needs to recognize that all the standards are interconnected and other existing standards development. Automatic load shedding needs to be left in PRC-006. Manual load shedding should be left in EOP-003 according to already existing standards proposed changes. The SAR be revised to call for removing the automatic UFLS requirements from EOP-003-1 and referring them to PRC-006-1 standard, and for removing the automatic UVLS requirements from EOP-003-1 and referring them to a new UVLS standard or PRC-006.
No
The SAR needs to recognize that all the standards are interconnected and other existing standards development. Automatic load shedding needs to be left in PRC-006. Manual load shedding should be left in EOP-003 according to already existing standards proposed changes. The SAR be revised to call for removing the automatic UFLS requirements from EOP-003-1 and referring them to PRC-006-1 standard, and for removing the automatic UVLS requirements from EOP-003-1 and referring them to either a new UVLS standard or PRC-006
No
Automatic load shedding needs to be left in PRC-006. Manual load shedding should be left in EOP-003 according to already existing standards proposed changes. The SAR be revised to call for removing the automatic UFLS requirements from EOP-003-1 and referring them to PRC-006-1 standard, and for removing the automatic UVLS requirements from EOP-003-1 and referring them to a new PRC-024-1 standard. In line with the comments for Question 6: R2 - remove this requirement because it refers to automatic load shedding plans, let this be covered by PRC-006-1 and PRC-024-1. R3 – add the qualification “coordinate manual load shedding plans”. R4 - remove this requirement because it refers to automatic load shedding plans, let this be covered by PRC-006-1 and PRC-024-1. R5 – add the qualification “implement manual load shedding plans”. R7 - remove this requirement because it refers to automatic load shedding plans, let this be covered by PRC-006-1 and PRC-024-1
No
The word “all” should be replaced with "applicable". The compliance requirement should focus on primary entity identified responsible for that compliance function. An example, might include a jointly owned facility (generator, substation, line, transformer, or capacitor bank) owned by one or more entities and operated by another. One identified entity should be identified and held responsible its UFLS relays whether through majority ownership, interconnection agreements, or contracts. Since ownership and operation can be divided, it is inappropriate to enforce compliance responsibilities on entities outside of their control.
No
R3.3 should be deleted as it does not directly apply. If volts / hertz requirements remain, they should be consistent with the proper IEEE standards.
Yes
 
No
Instead of reaching concurrence, entities should be just required to inform adjacent interconnected NERC entities of the assessment results. Otherwise entities could potentially be held responsible for inaction of another planning coordinator. The language could be changed to be consistent with the language in EOP-003 R3, such as, “Each Transmission Operator and Balancing Authority shall coordinate load shedding plans among other interconnected (entities)”.
Yes
 
No
MidAmerican notes that past under frequency event analyses are complex and that the minimum time frames for analysis and implementation should be increased to at least 2 years and exception requests for additional time should be allowed.
Yes
 
Individual
Patrick Farrell
Southern California Edison Company
No
SCE does not agree with the proposed reliability standard and, therefore, we cannot agree with the proposed Violation Risk Factors.
No
We do not agree with the proposed reliability standard and, therefore, we cannot agree with the proposed Measures.
No
We do not agree with the proposed reliability standard and, therefore, we cannot agree with the proposed Violation Severity Levels.
No
SCE does not agree with this revision and supports WECC’s position that "The standard should require the PCs within an interconnection to coordinate a UFLS Design with all other PCs within the interconnection and that the PCs should be required to develop a coordinated interconnection wide UFLS Design. As proposed the standard could conceivably result in as many different UFLS plans within WECC as there are Planning Coordinators.”
Yes
 
Yes
We agree in principle with the expanded scope for the Supplemental SAR.
We cannot comment on the proposed revisions to EOP-003-1, as their ramifications have not been studied in detail.
No
SCE agrees with WECC’s position that “the proposed standard fails to address UFLS relays which are currently part of the existing program which are owned by the customer. Recognition of customer owned relays is critical to have a successful program. To assure areas are covered, the LSE needs to be included in the Applicability section”.
No
SCE agrees with WECC’s position that “This approach fails to recognize the unique characteristics of the four individual interconnections. Frequency-time curves do not allow for specific and defined measurements and will leave individual entities defaulting to the lowest common denominator. If frequency-time curves are intended to define the boundaries, the determination of discrete set points would fall into the hands of the PCs leading to disagreements among entities. In addition, to determine the frequency-time curves through stability and dynamic modeling, one must establish discrete set points. Frequency-time curves are reverse engineering and require justification and correlation to the reliability of the interconnections – no such justification has been provided.”
SCE is unsure of the ramifications of this change and, therefore, cannot confirm that we are in agreement with the change.
 
No
SCE would hope that the drafting team provides additional clarification on this requirement, as we are unsure of what the team intends by “automatic switching of Elements”.
 
 
Group
IRC Standards Review Committee
Ben Li
IESO
No
No VRF for UFLS should be High. UFLS is only actuated because several other things did not work properly. For a VRF to be High, there must be a direct causal link to bad things happening (i.e. cascading, instability, blackout) as result of the requirement. If UFLS has to be actuated, we have already reached the bad things happening stage and this represents a last ditch effort to save the system.
Yes
 
No
The ability for the PC to comply with R1 and R2 requires ULFS entities and Transmission Owners to comply with this standard. The VSLs should clearly state that it is the PC who did not meet its obligations under R1 and R2 and not that non-compliance to R1 and R21 was the result of non-compliance by a third party which the PC relied on into meeting its obligations under this standard.
Yes
We agree; however, this standard should not disallow the ability for some PCs to group together to develop a wide area UFLS plan. To the extent some PCs do this, the standard should be written and performance measured in a manner that does not cause these PCs to duplicate the same documents that may already be provided by another PC for the same footprint.
Yes
 
No
Please see comments to 7.
No
We understand the concerns that EOP-003-1 contains redundant requirements. However, the Order 693 changes include revisions to EOP-003-1 that are in conflict with the supplemental SAR.
No
Generator owners are not included in the applicability of this standard. We understand from the SDT’s responses to the last posting that there is a separate project for generator requirements that could obligate them to provide required data to planning coordinators for underfrequency load shedding schemes. However, absent that standard, a generator owner has no obligation to provide needed data to a planning coordinator. If the generator owner fails to provide that data, then that planning coordinator could be found in violation of a requirement in PRC-006-1. NERC must recognize that registered entities may vote against PRC-006-1 if they are concerned about the ability to meet requirements which rely on yet to be approved or developed standards and/or definitions. Therefore, in a concerted effort to move proposed standards through the approval process, NERC must not enforce specific requirements upon a registered entity if that entity cannot meet a requirement because a supporting standard or definition is not yet in effect. We are also concerned that the ULFS standards requirements may not apply to new entities and loads that may be interconnected to the BPS such as those for Demand Response grid services. New technologies such as Smart Grid and Plug-In Electric Vehicles will become more prevalent in the near future and new entities may be aggregating these loads to offer grid services. Because it is unknown how these aggregators may be structured, they may not fall into the registered entity categories specified in this standard. NERC should be diligent in identifying new entities that existing approved standards should apply to and adjust the registry and standards accordingly.
Yes
 
Yes
 
No
We agree with the need for Planning Coordinators in neighboring regions “to identify and reach agreement on islands between its region and neighboring regions”. However, we believe new problems have been introduced. First, 2.3 under R2 is arbitrary and lacks any technical basis. There is no reason for splitting a island based on regional boundaries. Additionally, we are concerned that R1 may be viewed as an attempt to predict islands that may occur. Will a PC be held non-compliant if they predict incorrectly. There requirement needs to be clear that it is intended solely for the purpose of designing UFLS “islands”.
Yes
 
Yes
 
Yes