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View Response #754
Patrick O'Loughlin
Buckeye Power, Inc.9/7/2012 10:09 AMYes
The implementation plan for R1 and R2 are too fast for DPs that do not currently have UFLS systems to design, engineer, procure and appropriately deploy a UFLS system.  Also does not allow time to evaluate and develop mutal agreements to aggregate loads as allowed for in R1.
No
No
The differences in implementation levels between lower, moderate, high and severe are relatively minor and not in accordance with the descriptions.
Yes
No
See previous comments
Yes
View Response #756
David Thorne
Alvin Depew
Carl Kinsley
Potomac Electric Power Company9/7/2012 10:09 AMYes
No.  It does not appear that this draft lines up with all requirements with NERC PRC-006-1.  This RFC standard should be reviewed and modified to be consistent with and conform to all the applicable requirements of NERC PRC-006-1.
Some inconsistencies are described below:
1)  NERC Standard PRC-006-1 establishes nationwide performance criteria for UFLS schemes, including frequency versus time plots, which prescribe limits (both over and under frequency) within which the simulated system frequency response must remain.   Adherence to this performance criterion should be mentioned in the RFC standard.   
2)  NERC PRC-006-1 standard provides a frequency versus time threshold for generator over/under frequency tripping, within which individual generator frequency tripping must be modeled.   It appears that the generator underfrequency tripping criteria outlined in Requirement R12 of the RFC standard falls inside these NERC threshold boundaries, requiring detailed modeling of all generators.   In addition, this RFC standard does not establish any criterion for overfrequency tripping of generators, or for the collection of overfrequency trip points, which would be necessary to satisfy the modeling and performance criteria established by NERC PRC-006-1.   Over/under frequency generator tripping criteria should be established in the RFC standard consistent with NERC PRC-006-1 and PRC-024-1.
3) NERC PRC-006-1 imposes V/Hz limits as part of the UVLS performance criteria.  There is no mention of V/Hz criteria in the RFC standard.
4)  V4 of Draft 6 of PRC-006-RFC-01 removed all applicability qualifiers from paragraph 4.3 Generator Owners.   Without some form of applicability qualifier it is unclear what generator facilities are in scope for this standard.  As such, one might mistakenly conclude that it applies to small units not connected to the BES.  This standard should be consistent with NERC PRC-006-1, which limits generator applicability to the following:
• any facility consisting of one or more units connected to the BES at a common bus with total generation above 75 MVA (gross nameplate rating)
• individual generating units greater than 20 MVA (gross nameplate rating) directly connected to the BES
• generating plants/facilities greater than 75 MVA (gross aggregate nameplate rating) directly connected to the BES
Yes
The term “BES” should precede the phrase “capacitor banks” in Measurement M3 to be consistent with previous drafts of the standard and with Requirement 14.7, which requires overvoltage tripping data only on capacitor banks connected to the BES.    R3 and R16.2 should also use BES preceding capacitor banks.  The intent of these requirements and measures is to ensure adequate control of overvoltages on the BES following an UFLS event and should not be applicable to capacitor banks installed on lower voltage distribution facilities.
Yes
Yes
No
See responses above
No
View Response #757
Louis Slade
Michael Gildea, Chip Humphrey
Dominion9/7/2012 10:09 AMYes
1. We do not agree that a reliability standard should be effective, in the US, until it is approved by FERC. We are concerned that changes could be imposed as a regional standard goes through the NERC approval process and/or as it goes through the FERC approval process. We do not think it is prudent to expend the resources necessary to comply with a reliability standard until such time as it has been approved by FERC, as the changes made during the standards development process could substantially alter the requirements as approved by either the regional board or the NERC BOT.  And, because of these concerns, we cannot agree with an implementation plan that begins with board approval.
2. We do not agree with the response of the SDT to Wisconsin Electric Power’s comments in question 5. Our interpretation of the SDT’s response is that this regional standard could be applied to Generator Owners who are not included in the NERC compliance registry. If this is the intent of the SDT, we disagree. We do agree that any generator that meets the criteria contained in NERC’s Statement of Compliance Registry Criteria (III(c)) can be registered by NERC or a Regional Entity.
3. We do not agree that R10 should apply to Generator Owner. R9 requires the Planning Coordinator to establish a mitigation plan that meets R9.1 and R9.2. If the mitigation plan involves a Generator Owner, then there should be a requirement that the Planning Coordinator provide notification to the Generator Owner. Absent such notification, R10 should not apply.
4. We do not agree that R11 should be predicted upon R9, but instead should be predicated upon R10.
5. We do not agree with R12.1 as it still requires a Generator Owner to procure a service (load shed) for which we have found no willing provider. We prefer the SDT adopt requirements similar to those contained in the version of PRC-024-1that is being developed in Project 2007-09. Alternatively, we could accept modification of the requirement so that it only applies when the Distribution Provider offers load shed service.
 
Yes
We do not agree with the measures included in M10, M11 and M12 because we do not agree with the corresponding requirements (as indicated in our responses to question 1).
Abstain
Abstain
No
No, for reasons indicated in responses to question 1.
No
View Response #758
Scott Berry
Indiana Municipal Power Agency9/7/2012 10:09 AMYes
IMPA does not agree with requirement 10 in the way that each entity's compliance to the requirement is dependent on its participation in the "establishment" of the mitigation plan.  Entities may participate in the process, however, that does not guarantee that a mitigation plan will be established.  If one party does participate but does not agree with the mitigation plan, then all parties will be non-compliant with requirement 10 due to not establishing a mitigation plan.
 
IMPA does not agree with requirement 12.1 and its sub-requirements.  Reason is given in number 6.
 
IMPA believes requirement 15.2 is too vague and it seems to be a last catch all that can be left open to much interpretation for the Generator Owner and any auditor.
 
IMPA does not agree with the wording "required to comply with the relevant sections of Requirement R11 and Requirement R12" in Requirement R15 (and the same wording used in Requirement 14).  First, IMPA does not see the connection between Requirement R15 and Requirement R11.  It seems like the mitigation plan in R11 is coming from the Planning Coordinator and there is no need for the Generator Owner to send back this information to the Planning Coordinator.  Second, if there are parts of a requirement that are NOT relevant then those parts should be removed or deleted.
 
IMPA does not agree with Requirement 11.  If the mitigation plan from the Planning Coordinator involves potential equipment damage or could void a generating unit's warranty, a Generator Owner should not be required to implement the mitigation plan within three years.  This is where a party in Requirement 10 might participate in the work of a mitigation plan, but not in the establishment of the mitigation plan if the entity does not agree with the mitigation actions.
 
IMPA does not agre with the generator relay settings in Requirement 12.  The NERC Generator Verification SDT is working on PRC-024 standard which is the generator "ride-thru" standard.  The frequency set points in Requirement 12 do not correspond to the PRC-024 Attachment 1 form the draft of PRC-024 with some points allowing tripping of the generator unit within the "No Trip" area of the curves.  All Generator Owner requirements should be pulled from this regional standard, including removing Generator Owner from the applicability section.  The NERC PRC-024 will allow for a uniform application of generator set points and prevent each region drafting different generator trip points which might be more harmful to the reliability of the BES than beneficial.  The reporting of generator relay set points to the Planning Coordinator is also covered in PRC-024.
 
(I tried to include the current PRC-024 attachment 1 for the off nominal frequency capability curve but the copy and paste option does not work in this commenting section or any commenting section.  It would be convenient to be able to copy and past in these commenting boxes.)
 
 
 
Abstain
IMPA does not agree with measurement 10.  Ths measure is dependent on all entities' participation in the establishment of the mitigation plan per requirement 10.  If a mitigation plan is not established, all entities involved will be non-compliant, even if all entities can show participation.
Abstain
IMPA has no comment.
Abstain
IMPA has no comments.
No

No, this standard should not go to Category ballot.  The proper course of action would be for the SDT to discontinue the work on this draft standard, due to the following reasons:

First, the current NERC board approved UFLS standard (PRC-006-1) does not require the regions to have a regional UFLS standard as per the old NERC UFLS standard (PRC-006-0).  If RFC is looking to combine any type of legacy documents, it can use the current NERC standard (PRC-006-1).

Second, if there is any intent for the RFC Planning Coordinators to use this regional standard as their UFLS program as required by PRC-006-1, this intent should be fully disclosed to the industry before the start of the commenting period.  This will allow the industry to decide if it is proper for the UFLS program to be part of a regional standard and the stakeholders can make the proper comments with the knowledge that this will be the UFLS program implemented by the Planning Coordinators.  IMPA does not bellieve that developing a regional standard is the proper method for the Planning Coordinators to develop their UFLS program.

Third, the RFC UFLS draft standard does not follow the PRC-006-1 Applicability section correctly.  PRC-006-1 applies to Planning Coordinators, UFLS entities (Transmission Owners and Distribution Providers), and Transmission Owners that own Elements identified in the UFLS program established by the Planning Coordinators.  UFLS entities cover all entities that are responsible for the ownership, operation, or control of UFLS equipment as required by the UFLS program established by the Planning Coordinataors.  The NERC UFLS SDT saw the need for UFLS entities to fill potential gaps where Transmission Owners are providing UFLS for Distribution Providers, but the Transmission Owners were not registered as Distribution Providers.  This might be a registration issue, but a standard cannot fix registration issues.  Currently in place in many Midwest states (Ohio, Indiana, Michigan, and Illinios), the UFLS is performed at the transmission level and not at the distribution level with tariff agreements in place.  The use of UFLS entites would help in keeping these tariff agreements in place and not require entities to make an investment in equipment when there is currently a system in place that works.

Last, in requirement 12.1 and its sub-requirements, the standard forces generators that do not meet the performance requirements (non-conforming) in the standard to either: 1) make substantial investments to meet performance requirements imposed on them after they are already interconnected and in commercial operation, or 2) to force them into an agreement for compensatory load shedding with a limited number of entities that can offer such service and with no market to inform pricing of such service.  Either option is a significant burden on the competitiveness of these generators which results in a substantial burden on competitive markets.

Compensatory load shedding should NOT be allowed for two reasons: 1) the standards should not force agreements to be made (most likely financial agreements); and 2) the UFLS would become a highly complex scheme with dynamic settings to reflect the status of the non-conforming generator, e.g., if the unit were off-line, then too much load would be "armed" to trip, so, those relay settings would need to be changed when the unit was off-line.

The complexity of a UFLS program that would have to track the status of non-conforming generators is staggering.  For instance, in order to protect the granularity of supply/demand balance that the drafters of the standard believe is important, the UFLS relay settings would need to change every time the generator changed output.  For instance, a non-conforming generator running at 300 MW would presumably have 300 MW of compensatory load shedding.  If it were running at 200 MW, then we would want the 300 MW of compensatory load shedding dropped to 200 MW.  How would such a thing be possible if we are limited to a finite level of distribution circuits whose load varies minute to minute with different load patterns, with varying levels of critical loads (e.g., hospitals) and non-critical loads on those circuits?  What UFLS step?  Would it be multiple steps?  If generators were providing regulation service, the relay settings would need to change minute by minute on different circuits depending on actual loads on those circuits.  If this was not in place, would the generator be prevented from participating in the regulation service ancillary services market?  Compensatory load shedding is ill-conceived and highly impractical.

The NERC-wide standard recently approved by the BOT takes the correct approach.  Existing non-conforming generators of sufficient size to matter should be modeled and the UFLS program be designed in a robust enough fashion to handle the generator.  The only requirement that FERC has is that the generator be simulated as tripping if it cannot ride through a Category B and C contingency (paragraph 1787 in Order 693).  FERC does not require compensatory load shedding for non-conforming generators.

No
View Response #759
Howard Rulf
We Energies9/7/2012 10:09 AMYes
As requirement R2 is written, Distribution Providers that have less than or equal to 50 feeders shall implement the modified UFLS program described in R2.  By using the word “shall” in R2, a Distribution Provider with less than or equal to 50 feeders does not have the option to implement the UFLS program described in R1. 
Requirements R7 through R10 need to be revised to show coordination among Planning Coordinators when an identified area of credible islanding is part of multiple Planning Coordinator areas.  R5 of the NERC Board of Trustees approved continent-wide UFLS standard (PRC-006-1) provides an example of such coordination. 
The following text in requirement R9.1 is grammatically incorrect: 
“…where the amount of additional UFLS capability Load to be shed in the island area…”  The text should state “…where the amount of additional UFLS capability in the island area…”
In addition, the text “in excess of the 25% specified in R1.1 or R2.1” needs to be deleted from R9.1.  Any additional UFLS capability installed in an area of credible islanding that has the same setpoints as the UFLS capability required in R1.1 or R2.1 should be allowed to be counted as part of the overall 25% UFLS capability required in R1.1 or R2.1.  There is no technical reason that the UFLS capability installed in an area of credible islanding cannot serve the dual purpose of mitigating an underfrequency event in the area of credible islanding as well as mitigating an overall system UFLS underfrequency event.  The UFLS relays are going to trip load in either case, as the UFLS relays cannot distinguish between the types of underfrequency events that initiated the tripping. 
Table 1 of requirement R12 must be revised to insert the word “Under” between the words “Automatic” and “Frequency” in the Minimum Time Delay column for the ≥ 59.5 Hz. entry as automatic overfrequency tripping would not be allowed per the table’s current construct. 
Requirement R11’s grammatical structure appears to have a circular reference within R11 regarding the use of the words mitigation plan.  R17 provides an example of how R11 should be worded.  The following is suggested text for R11 based on R17’s wording. 
“Each Distribution Provider, Transmission Owner and Generator Owner shall implement the Planning Coordinators mitigation plan (as determined in Requirement R9) within three years of the completion date of the Planning Coordinators mitigation plan (as determined in Requirement R9).  “
Requirement 14.6 is written too open ended as evidenced by the use of the text “…additional Load shedding schemes…” or “…any other schemes...”  It should be left to the Planning Coordinator to determine what specific additional information is required for the Planning Coordinator’s database. 
As such, R14.6 needs to be reworded to strike the text after “load-restoration schemes.”  An example of the reworded requirement is: 
“Information describing non-Fault clearing tie-tripping schemes, islanding schemes, and automatic load-restoration schemes.  “
Requirement 15.2 as written is too open ended as evidenced by the use of the text “…any other schemes…”  It should be left to the Planning Coordinator to determine what specific additional information is required for the Planning Coordinator’s database.  As such, R15 .2 needs to be deleted. 
Similar to our comments regarding requirements R7 through R10 above, R16 needs to show coordination among Planning Coordinators when an identified area of credible islanding is part of multiple Planning Coordinator areas. 
Additionally, due to following text at the end of R16:  “…and shall include, but not be limited to the following…,” the Planning Coordinator would be non-compliant if the Planning Coordinator only considered R16.1, R16.2, and R16.3 in its assessment. 
Requirement 17 as written is too open ended as evidenced by the text “...other protection system…”  Requirement 17 needs to focus on UFLS program changes only.  As such, replace the text “or other protection system” with the text “program” 
Yes
In Measurement M12, the word “that” needs to be inserted after the text “Each Generator Owner”
In Measurement M14, the text “UFSL” needs to be changed to “UFLS” 
Yes
Yes
No
For clarity, R11 and R17 should be added to the Implementation Plan.
The draft RFC UFLS standard appears to have multiple requirements that are either duplicate or less stringent requirements than that of the NERC Board of Trustees approved continent-wide UFLS standard (PRC-006-1).  At a minimum, RFC should delay this standard until after the NERC continent-wide UFLS standard is effective. At such time, the SDT can align the RFC UFLS standard with the NERC continent-wide UFLS standard.  However, in light of the new NERC continent-wide UFLS standard, the SDT should re-evaluate the reliability need for a RFC regional UFLS standard and consider retiring the legacy guides after the NERC continent-wide UFLS standard becomes effective. 
Per the RFC Standards Development Procedure, there are missing compliance elements in the draft standard.
In accordance with the ReliabilityFirst Reliability Standards Development Procedure, Board Approval December 6th, 2007 Standards Committee Modified April 1st, 2008 - Board Concurrence May 22nd, 2008, "A Standard shall consist of the format requirements shown in the Regional Reliability Standard Template. These requirements apply to the development and revision of Standards. These requirements are necessary to achieve Standards that are measurable, enforceable, and consistent… "
Within the Compliance Monitoring Process, please include these missing required elements:
Define for each measure:
• The specific data or information that is required to measure performance or outcomes.
• The entity that is responsible to provide the data or information for measuring performance or outcomes.
• The time period in which performance or outcomes is measured, evaluated, and then reset.
• Measurement data retention requirements and assignment of responsibility for data archiving.
No
View Response #760
Thad Ness
American Electric Power (AEP)9/7/2012 10:09 AMYes
However, our comment regarding R3 has language that could read contrary to the stated Time Horizon. We recommend removing the words “…as a result of an UFLS event.” From R3.
Yes
AEP agrees with additional information, but M3. needs to be adjusted, as it is not entirely consistent with Requirement 3. M3 is event driven, while R3 is driven by PC assessment.
No
 For R1, Severe VSL the last condition needs to be reconsidered as it could be read to infer that participation to collectively implement by mutual agreement is required.
R3 – What is meant by the “percentage of automatic switching?” Percentage of number of banks, percentage of MVARs or something else?  This needs to be clarified to remove ambiguity.
R12 – The VSLs for this requirement would need to be revisited by the SDT based on the comments that we provide regarding R12 in question 6.
R12 - We did notice an error the last condition should state, “The Generator Owner that owns a unit(s) withOUT…”
The word “with” needs to be replaced with “without”
Yes
No
AEP offers the following input to the Standards Drafting Team.  While this project has been under development, there has also been significant progress on NERC related standards.  There are a number of overlapping and possibly conflicting requirements with the now NERC Board approved PRC-006-1, and also with the coordination of generator off-nominal frequency curves between NERC Standards PRC-006-1 and draft PRC-024-1.  AEP believes that more work should be done to remove similar requirements and overlapping elements, and resolve inconsistencies between this draft Regional standard and the NERC standard(s).
AEP also offers these specific comments:
R1.7 & R2.2 – “For installations where motor loads or distributed generation may be isolated, additional supervision (e.g. undercurrent) shall be used to avoid false operation during Fault isolation.”  The wording needs to have the word “should” in place of “shall”.  This would be addressed in the misoperation process.  It is often not practical to determine how long a disconnected distribution feeder will remain energized due to an induction machine on the load.
R3 – It is not clear if this requirement is event driven or a long-term planning based requirement.  Our assumption is it long-term planning and not event driven. The words “as a result of an UFLS event” need to be removed. Also, AEP questions M3., and believes it needs to be reworded as it is not entirely consistent with Requirement 3. M3 is event driven, while R3 is driven by PC assessment.
R12 – With respect to Table 1 of Requirement 12 of this draft, the frequency and minimum time delays of the standard should be evaluated for consistency with the proposed generator off-nominal frequency capability curves in NERC Standard PRC-006-1 “Development and Documentation of Regional UFLS Programs” Attachment 1 and draft NERC Standard PRC-024-1 “Generator Performance During Frequency and Voltage Excursions” Attachment 1.  The frequency and time values currently proposed by RFC would permit a generating unit’s underfrequency trip point to be set in compliance with RFC Standard PRC-006-RFC-1 but the setting would not be in compliance with NERC Standard PRC-024-1.  This inconsistency can only lead to future compliance confusion.
With respect to Requirement 12.1 of this draft we find it acceptable to require the Generator Owner, where technically feasible, to set their automatic underfrequency protection, and where not automatic, their underfrequency tripping procedures to conform to a Table 1 modified to be consistent with PRC-024-1 Attachment 1, as described above.  We also find it acceptable to require the Generator Owner to supply the data listed in Requirements 15 to the Planning Coordinator, Transmission Owner and/or Distribution Provider. 
AEP recognizes the need to coordinate the underfrequency tripping of generators with automatic underfrequency load shedding programs.  Furthermore, we recognize the need to evaluate the impact that the premature tripping of a generating unit may have on the Bulk Electric System during a frequency excursion and the potential need to install additional load shedding to compensate for the loss of such a generator.
However, we strongly feel that the requirement of the Generator Owner to arrange for load shedding to be installed should be removed from the standard.  We believe that the requirement of the Generator Owner to arrange for load shedding is inconsistent with the resolution between NERC Standard PRC-006-1 “Development and Documentation of Regional UFLS Programs” and draft NERC standard PRC-024-1 “Generator Performance During Frequency and Voltage Excursions.”  These standards only require that Generator Owners document relay settings or equipment limitations that prevent conformance to the off-nominal frequency curves of those standards and that Planning Coordinators develop and document underfrequency load shedding programs that account for generators whose trip characteristics do not conform to the off-nominal frequency curves of those standards.  Neither NERC standard requires the shedding of load by Generation Owners.
As written, the RFC standard does not contain any mechanism by which a Generator Owner can require a Transmission Owner or Distribution Provider to install load shedding on the Generator Owner’s behalf.  A Generator Owner who owns no transmission or distribution, may be forced into non-compliance with the standard if they cannot reach an agreement with a Transmission Owner or Distribution Owner to shed load.  The requirement (R12) causes one entity’s compliance to be dependent on the cooperation of another entity and such dependence has been problematic in certain instances where it has been proposed in other draft standards.
It is for the reasons documented above that AEP strongly believes that Requirement 12 and its associated measures and violation severity levels should be revised by removing the requirement for Generator Owners to arrange for load shedding.
Other - There should be a requirement in-between R16 and R17 for a peer review process to develop an implementation plan based on the results of the Planning Coordinator’s assessment.  Then the proposed R17 could be the requirement to implement the action plan.
Each Distribution Provider, Transmission Owner or Generator Owner for which UFLS or other protection system changes are recommended by the peer review and remediation process, (see newly proposed requirement above) shall complete the changes within three years of the completion of the finalization of the action plan to remediate deficiencies resulting from the Planning Coordinators assessment (as determined in Requirement R16)
Yes
View Response #761
Gregory Miller
BGE9/7/2012 10:09 AMYes
BGE would like to comment on the following requirements:
R1.8 A “low as practical” requirement adds too much subjective uncertainty to an auditable standard. Leave the “not greater than 75% of nominal” requirement.
R3. SDT should include a stronger statement excluding capacitors that are not connected to the BES. BGE recommends a modification to the proposed language like “existing BES-connected capacitor banks”.  Although distribution banks provide reactive support to transmission, they are frequently located on the regulated side of tap changers or line-regulators, and therefore are not relevant to the concern. It should also be noted that fixed banks are appropriately used in many distribution applications.
R12. It is unclear as to how a discretionary trip would fall into the values in Table 1. For example, if the only UnderFrequency protection was a discretionary trip at 58 Hz, would more protection need to be installed to meet the 15 seconds and 120 seconds trip points as described in Table 1? Or is a single trip point sufficient?
BGE feels the time horizons are appropriate.
Yes
BGE has no comments regarding the modifications to the Measures.
Abstain
BGE has no comments regarding the modifications to the VSLs.
Abstain
BGE has no comments regarding the modifications to the VRFs.
No
BGE feels that the SDT needs to address the concerns expressed under Q1 prior to the Standard being ready for Category Ballot.
No
View Response #762
Jason Marshall
Midwest ISO9/7/2012 10:09 AMYes
We do not support the concept of identifying arbitrary islands for the purpose of establishing a UFLS program and do not believe it is necessary to identify islands to establish the program.  Many parts of the BES do not have characteristics that necessarily result in them developing into any particularly islanding scenario. 
 
We do not support Requirement 6 as it is essentially mandating a stakeholder process and is administrative.  While we are supportive of a stakeholder process, we do not believe it should be mandated in a reliability standard and do not believe this requirement provides a reliability benefit. 
 
Requirement 16 in the RFC standard potentially conflicts with Requirement 4 in the NERC standard.
 
The NERC standards reads assess the design, whereas the RFC standard reads assess the design and implementation. How we are to assess what has been implemented is not clear.  One interpretation would be the UFLS database contains a record of what is implemented in the field and we perform an assessment of that. Another interpretation would be to assess that the implementation of UFLS relays in the field has occurred.  Planning Coordinators should not be making field verifications of UFLS relays. So language should be clarified to the former.
In addition, we support the comments submitted by ATC regarding this question.
Yes
We agree with the comments submitted by ATC for this question.
Abstain
Yes
No
The work on this regional standard should be halted.  NERC recently completed their work on the UFLS standard.  It eliminates the need for regional work on UFLS standards by eliminating the "fill-in-the-blank" components.  Many of the RFC requirements are duplicative.  When RFC commenced this effort, it made sense because there was not a NERC standard but now that there is a NERC standard, the RFC standard is largely duplicative and unnecessary.  At the very least, RFC should halt the work until FERC rules on the NERC standard to see what list of directives NERC must respond to.  This might change the direction of the RFC standard.
No
View Response #763
Bob Thomas
NA
Illinois Municipal Electric Agency9/7/2012 10:09 AMYes
Abstain
Abstain
Abstain
No
Illinois Municipal Electric Agency (IMEA) appreciates the SDT's efforts and responsiveness leading to the development of Draft 6; however, it is our understanding from Sector representatives and representatives on the NERC PRC-006-1 SDT that region-specific UFLS standards are no longer necessary.  If the PRC-006-RFC-01 SDT believes this region-specific standard is necessary, IMEA would appreciate the SDT addressing that point before the Category Ballot.  In addition, if the SDT decides to move forward with this proposed region-specific UFLS standard, IMEA recommends that the SDT address inconsistencies with entity applicability and requirements as specified in NERC's PRC-006-1.  Finally, IMEA supports the GO-related comments to this survey as submitted by Indiana Municipal Power Agency.
Abstain
View Response #764
Andrew Pusztai
American Transmission Company9/7/2012 10:09 AMYes
R1 – Modify the wording of “The Distribution Providers automatic UFLS program” to “The automatic UFLS program of a Distribution Provider or a collective group of Distribution Providers”. This wording would more clearly convey the idea that the sub-requirements apply to the UFLS program of a “stand alone” Distribution Provider or the UFLS program of a collective group of Distribution Providers.
R1.1, R2.1, R7, & R14.2 – Replace “forecasted annual peak hour” with “next forecasted Year One peak hour”.
R3 & R16.2 – Replace “capacitor banks and reactors” with “capacitor banks and inductor banks” because both capacitor banks and inductor banks are reactors.
R4.4 & R7 – Insert a new R4.4, ahead of the existing R4.4, with the wording, “Areas of credible islanding shall have a next forecasted Year One peak hour Load of greater than 1,000 MW, which is within or partially within their area of responsibility”, and remove the associated qualifying wording from R7 because it would be redundant.
R8 – Modify the wording of “of applying the island methodology” to “of applying the island methodology (to as determined by R7)” to be consistent with the inclusion of this qualification in R9.
R9 – Add wording that is consistent with R16 to R9 such as “This mitigation plan shall include the effects of neighboring Planning Coordinator area and may be developed jointly with other Planning Coordinators that are within the credible island.”
R9.1 – Change the existing wording to “To cover potential generation/Load imbalances in the island area, Distribution Providers shall install additional UFLS capability in the island area in excess of the minimum requirements specified in R1.1 or R2.1 . . . determined by engineering assessments in accordance with the design requirements in R1 and R2.” for added clarity.
R10 – Expand the wording to “. . . establishment of the mitigation plan by the Planning Coordinator (as required in Requirement R9.” for added clarity.
R12.1 – Add the following qualification to the second sentence, “In those cases where a generator must be tripped for its own underfrequency protection outside the specifications in the above Table 1 and tripping of the generator prevents acceptable effectiveness of the UFLS program design . . .” The loss of a generator does not have to be compensated if the effectiveness of the ULFS program is sufficient despite the tripping of certain generators. 
R14 – Expand the wording to “with the relevant sections of Requirement R1, Requirement, R2, Requirement R3 or Requirement R11” because R14.7 refers to the provision of data for the reactive elements mentioned in R3. 
R14.x - Add a sub-requirement to R14 that identifies system model location of the UFLS data, “Transmission interconnection location of the forecasted Year One peak hour load”.
R14.7 – Replace “capacitor banks connected to the BES” with “existing capacitor banks and inductor banks to control over-voltage in accordance with the assessment performed by the Planning Coordinator in Requirement R16”. The transmission capacitor banks and inductor banks used to control over-voltage may be connected to non-BES portions of the transmission system.
R16 – Expand the wording to, “. . . may be performed jointly with other Planning Coordinators within the credible island . . .” for more clarity.
R16.1 – Consider replacing “the current frequency set points” with “the existing frequency set points”.
R16.3 – Consider replacing “Disturbance that cause” with “Disturbances that are expected to cause”.
R17 – Consider consolidating R11 and R17 into one Requirement. The revised Requirement could be the wording in R17 and simply refer to recommended changes “(as determined in R9 and R16)”.
R18, R18.2, & R18.3 – Remove the reference to ‘other entities” because with the approval of PRC-006-1, only Planning Coordinators are responsible for UFLS data and UFLS program assessments. Remove the wording of “and entities” from R8. Replace the wording of “neighboring entities” with “neighboring Planning Coordinators” in R8.2 and R8.3.
R18.1 – Add the wording of, “. . . and assessment results required in R16 . . .” to require coordination on the assessment with Planning Coordinators internal to RFC, which would be consistent with obligation in R18.2 to coordinate on the assessment external to RFC.
Yes
In M5, the wording should be “within 15 calendar days” to agree with R5. Correct the wording at the end of the paragraph to “request per Requirement R5”.
In M8, the wording should be “within 30 calendar days” to agree with R8.
In M12, the wording might be changed to, “Each Generator Owner that owns” or Each Generator Owner owning”. Consider modifying the wording to “. . . dated evidence such as underfrequency tripping settings or procedures that demonstrate its underfrequency protection conforms to Table 1 . . .” for more clarity.
In M14, correct the wording of “Requirement 2” to “Requirement R2” and “UFSL” to “UFLS”. Per the comment on R14 above, add “Requirement R3” to the text.
In M15, the wording should be “within 45 calendar days” to agree with R15.
Abstain
Yes
No
In general, ATC thinks that that the RFC should defer development of the RPC-006-RFC-1 standard until the RFC gains enough experience with the PRC-006-1 standard to determine whether it is insufficient.
In addition, ATC does not believe that the standard is ready for Category Ballot until the comments made in Question 1 regarding R12.1 and R14.7 are adequately addressed.
No
View Response #765
Doug Hohlbaugh
Sam Ciccone, Dave Folk
FirstEnergy Corp9/7/2012 10:09 AMYes
See response to Question 6
See response to Question 6
Abstain
See response to Question 6
Abstain
See response to Question 6
Abstain
See response to Question 6
No
FirstEnergy believes further development of this standard is no longer needed based on progress made on a new NERC Board of Trustee approved PRC-006 version 1 standard.  Having this regional standard in addition to the new version 1 NERC standard causes industry confusion and duplication of compliance efforts.
 
We thank the drafting team for their dedication and hard work to draft a standard intended to support NERC's fill-in-the-blank standard PRC-006-0 which requires the Regional Reliability Organization (now Regional Entity) to document and implement UFLS requirements for its footprint.  FirstEnergy initially supported RFC’s effort to develop this PRC-006-RFC-01 standard as it served two important roles 1) elimination of legacy UFLS requirements and 2) the new PRC-006-RFC-01 standard could help influence the development of the NERC continent wide standard PRC-006-1.
 
The purpose statement of this RFC standard emphasizes the original scope as it states “To establish ReliabilityFirst requirements for automatic underfrequency Load shedding (UFLS) to support NERC Reliability Standard PRC-006.”  However, the NERC Board of Trustees approval of PRC-006-1 on November 4, 2010 eliminates the “fill in the blank” need and stated purpose of this RFC standard.    FirstEnergy concludes that this standard can not move forward without a concurrent proposal to include a regional variance in the new NERC PRC-006-1 standard to make clear that for the RFC footprint the RFC standard prevails.  Otherwise, the difference in approach between the two standards causes confusion and duplication of compliance efforts.
 
We cite these additional reasons why the RFC standard PRC-006-RFC-01 should not go further in the approval stages:
 
• UFLS Program Responsibilities - In the NERC PRC-006-1 standard, the UFLS program is developed by the Planning Coordinator (PC) per Requirement R1, while in the RFC standard PRC-006-RFC-01, the UFLS program is developed by the Distribution Providers in Requirements R1 and R2. This will make it very difficult for entities in the RFC region to comply with both standards.
 
• Generator Function Applicability and further NERC Standards Development Efforts - The RFC standard is applicable to the Generator Owner (GO) while the NERC PRC-006-1 standard is not applicable to any Generator functional entity. However, NERC is in the process of creating a separate standard, PRC-024-1 (Generator Performance During Frequency and Voltage Excursions) which will cover the Generator function. Furthermore, the settings specified in Requirement R12 of PRC-006-RFC-01 are not consistent with neither the proposed NERC PRC-024-1 standard nor the industry accepted practices described in IEEE standard C37.106 (Guide for Abnormal Frequency Protection for Power Generating Plants).
 
In conclusion, we believe that RFC should re-evaluate the need for their regional standard.  We suggest they table the effort until they have (1) carefully determined the feasibility of an entity in the RFC region to comply with both standards; and (2) determined if the BES within the RFC footprint has unique topology/characteristics that require region specific requirements to maintain BES reliability.
Abstain
View Response #767
Annette Bannon
Mark Heimbach PPL Martins Creek, LLC
Elizabeth Davis, PPL Brunner Island, LLC
PPL Lower Mount Bethel Energy, LLC9/7/2012 10:09 AMYes
Abstain
Abstain
Yes
No
PPL Generation concurs with others who believe that this standard is no longer needed based on the status of NERC PRC-006 version 1 standard.  The new PRC-006-1 standard eliminates the need for regional standards.  PPL appreciates the effort by the drafting team and RFC to develop the regional standard but we are concerned that duplicate standards may cause confusion and needless duplication of compliance effort.
Abstain
View Response #769
Brenda Truhe
PPL Electric Utilities9/7/2012 10:09 AMYes
Abstain
Abstain
Abstain
No
PPL EU concurs with others who believe that this standard is no longer needed based on the status of NERC standard PRC-006-1.  The new PRC-006-1 standard eliminates the need for regional standards.  PPL EU appreciates the effort by the drafting team and RFC to develop the regional standard but we are concerned that duplicate standards may cause confusion and needless duplication of compliance effort.
Abstain
View Response #770
Mark Kuras
Albert Dicaprio
William Harm
Patrick Brown
Mark Sims
PJM9/7/2012 10:09 AMYes
Yes
Yes
Yes
No
Further development of this standard is no longer needed because of the status of the NERC PRC-006 standard. Having the RFC standard and the NERC standard in place will be confusing for the members of RFC. The fill-in-the-blank aspects of the old NERC standard have been eliminated so the need for this RFC standard no longer exist. RFC shoul seriously evaluate the need to continue this effort.
Yes