Automatic Under Frequency Load Shedding Requirements (PRC-006-RFC-01) Sixth Comment Period - 01/12/11 02/10/11

Transcription

1 Automatic Under Frequency Load Shedding Requirements (PRC-006-RFC-01) Sixth Comment Period - 01/12/11 02/10/11 Question 1 Subsequent to a review performed by NERC staff, the SDT has reformatted and modified certain requirements of the draft PRC-006-RFC-01 standard. Do you agree with the reformatted structure and modified requirements of the standard? If not, please provide specific suggestions. Answers Frequency Yes 3 No 8 5 Commenter Answer Comment Response Patrick O'Loughlin - Buckeye Power, Yes Thank you. Inc. David Thorne - Potomac Electric Power Company (Alvin Depew, Carl Kinsley) No No. It does not appear that this draft lines up with all requirements with NERC PRC This RFC standard should be reviewed and modified to be consistent with and conform to all the applicable requirements of NERC PRC Some inconsistencies are described below: The RFC UFLS SDT has performed a review of the NERC PRC standard and draft PRC- 006-RFC-01 requirements to ensure the RFC requirements either are more stringent than a NERC reliability standard or address matters that the NERC reliability standard does not cover. A whitepaper detailing the reasons for the need for the regional PRC-006-RFC-01 standard has been developed. 1) NERC Standard PRC 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 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 1) The performance criterion in the NERC PRC standard must be adhered to regardless of the Requirements in the RFC PRC-006-RFC- 01 draft standard. 2) The time vs. frequency table in R12 (R8 in current draft) has been modified to be consistent with the curve proposed in the draft NERC PRC and PRC standard.

2 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 Over/under frequency generator tripping criteria should be established in the RFC standard consistent with NERC PRC and PRC ) NERC PRC imposes V/Hz limits as part of the UVLS performance criteria. There is no mention of V/Hz criteria in the RFC standard. 3) Since the NERC PRC-006-RFC-01 standard imposes V/Hz limits as part of the UFLS performance criteria, there is no need to address it in the RFC standard. Louis Slade Dominion (Michael Gildea, Chip Humphrey) No 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 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 4) The Generator Owner applicability, absent qualifiers, defaults to the criteria contained in NERC s Statement of Compliance Registry Criteria (III(c)). 1. ReliabilityFirst standards are mandatory and enforceable (without monetary penalties for non compliance) upon the effective date after ReliabilityFirst Board approval for applicable entities that are members of ReliabilityFirst. This is based on the condition of Membership as

3 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. stated in the ReliabilityFirst By Laws. ReliabilityFirst standards are then mandatory and enforceable (with monetary penalties for non compliance) to all applicable entities within the ReliabilityFirst footprint upon approval by the FERC. 2) The Applicability section of draft 6 had been modified to simply state Generator Owner. The Generator Owner applicability, absent qualifiers, defaults to the criteria contained in NERC s Statement of Compliance Registry Criteria (III(c)). 3. R10 of the standard has been removed from the current version of the standard. A new R6, Part 6.2 has been added to address your concern. The new R6, Part 6.2 states Each Planning Coordinator shall invite, in writing, the participation of Distribution Providers, Transmission Owners and Generator Owners, in an identified area of islanding, in the establishment of a mitigation plan that addresses generation/load imbalances in excess of 25 percent. 4. We do not agree that R11 should be predicted upon R9, but instead should be predicated upon R The SDT believes the reference to R9 in R11 (reference to R6 in R7 in current draft) is correct. The mitigation plan is developed by the Planning Coordinator in R6 (in current draft) and the applicable entities are required to implement the mitigation plan in R7 (in current draft).

4 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 Alternatively, we could accept modification of the requirement so that it only applies when the Distribution Provider offers load shed service. Mark Ringhausen - ODEC No ODEC 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 or that it will be completed. The co-dependency on other entities for compliance must be eliminated. ODEC does not agree with requirement 12.1 and its sub-requirements. Reason is given in number 6. ODEC believes requirement 15.2 is too vague and seems to be a last catch all that can be left open to much interpretation for the Generator Owner and any auditor. Not well enough defined for entity or auditor compliance to be understood. ODEC does not agree with the wording of 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, ODEC 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 5. The SDT considered other methods to allow a generator to stay in service but meet the standard requirements. This method of procuring additional load shedding has been deemed to be the most fair by the SDT, in that it does not burden the DP s with extra load shedding responsibilities due to a generator which does not conform to the time vs. frequency curve. This practice of procuring additional load shedding is also consistent with a number of Legacy RFC UFLS programs. The SDT agrees and has removed the old R10 from the standard. Please see response to question 6. The SDT agrees and R15, Part 15.2 has been removed from the draft standard. The SDT believes that information furnished by the Generator Owner to the Planning Coordinator is vital for proper modeling when establishing the mitigation plan.

5 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. ODEC 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. ODEC does not agree with the generator relay settings in Requirement 12. The NERC Generator Verification SDT is working on the 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 from the draft of PRC-024 with some points allowing the 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 Owners from the applicability section. The NERC PRC- 024 should allow for a uniform application of generator set points and prevent any region drafting different generator trip points which might be more harmful to the reliability of the BES. Scott Berry - IMPA No 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 A new R6, Part 6.2 was added to the standard which requires the Planning Coordinator to invite the participation of the applicable entities in the establishment of the mitigation plan. The new R6, Part 6.2 is as far as the standard can go in ensuring a mutually agreed upon mitigation plan. The Table 1 listed in R12 (R8 in current version) has been replaced with the generator frequency vs. time curve listed in the draft PRC-024 standard. At such time the NERC PRC-024 standard is approved, consideration for the removal of R12 (R8 in current version) will be considered. The SDT agrees and has removed the old R10 from the standard.

6 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 seem 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 parats 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. Please see response to question 6. The SDT agrees and R15, Part 15.2 has been removed from the draft standard. The SDT believes that information furnished by the Generator Owner to the Planning Coordinator is vital for proper modeling when establishing the mitigation plan. A new R6, Part 6.2 was added to the standard which requires the Planning Coordinator to invite the participation of the applicable entities in the establishment of the mitigation plan. The new R6, Part 6.2 is as far as the standard can go in ensuring a mutually agreed upon mitigation plan.

7 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.) Howard Rulf - We Energies No 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) The Table 1 listed in R12 (R8 in current version) has been replaced with the generator frequency vs. time curve listed in the draft PRC-024 standard. At such time the NERC PRC-024 standard is approved, consideration for the removal of R12 (R8 in current draft) will be considered. R2 has been modified to apply to the PC rather than the DP. The SDT has modified R2 to state that that a PC shall have the option to assign the frequency set points in R1 if so chooses. Since R5 of the NERC PRC standard already covers Planning Coordinator coordination, there is no need to cover it in the draft RFC PRC-006-RFC-01 standard.

8 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 The SDT agrees and has modified R9 (R6 in current draft) accordingly. 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 The SDT agrees and has modified R9 (R6 in current draft) accordingly. Table 1 of requirement of R12 (R8 in the current draft) has been removed from the standard. A new frequency vs. time curve (consistent with the NERC PRC standard) has been added as an attachment to the standard. R11 (R7 in the current draft) has been modified based on your comment to remove the circular reference.

9 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. R14 has been removed from the standard since it is covered by the NERC PRC standard. The R15, Part 15.2 has been removed from the standard based on your concern Within R16 (R10 in current draft), a new R10, Part 10.4 has been added to specifically require the PCs assessment to include the effects of neighboring Planning Coordinator areas. R5 of the NERC PRC standard also covers coordination between Planning Coordinators, so there is no need to specifically address it in the draft RFC PRC-006-RFC-01 standard. Additionally, due to following text at the end The SDT agrees and have removed the

10 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 language in question from R16 (R10 in current draft). The SDT agrees and has modified R17 (R11 in current draft) based on your concern. Thad Ness - AEP Yes Thank you Gregory Miller - BGE No 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. While as low as practical is the goal of the requirement, the SDT did include the measureable amount of 75% of nominal. 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. Point out that 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. Jason Marshall - MISO No 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 R3 has been removed from the standard since it is already covered in the NERC PRC standard. In the Eastern Interconnection, a significant overall decrease of system frequency, while the system is fully interconnected, has a very low probability of occurrence. UFLS, therefore, functions more as a necessary safety-net for islands that may form as a consequence of a

11 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. severe disturbance. It is worthwhile to keep islands from going black thus allowing generating units to remain online and facilitating more immediate load restoration. The process outlined in R3 through R5 is intended to avoid identification of merely arbitrary islands. Furthermore, the standard does not require islands to be forthcoming from the island identification criteria, only that identification criteria be documented and applied, and in the case where no islands are identified, a Planning Coordinator would not be non-compliant. The standard also recognizes the possibility that some islands may not have adequate protection by the base UFLS program specified as an outcome of R1 and R2 and may need extra mitigation measures which would then be established by the process outlined in R6 through R7. R5 and R6 (R4 and R5 in current draft) provide the opportunity for peer review of the Planning Coordinator s island identification criteria. As part of a thorough peer review process, the Planning Coordinator needs to consider feedback from commenting entities and respond to the commenting entities detailing its consideration of the comments received. 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 R16 (R10 in current draft) has been modified to require an assessment of the effectiveness of the implementation of the UFLS programs and not the design (the design piece is covered in the NERC PRC standard.) R16 s (R10 in current draft) intent is for the Planning Coordinator to perform an engineering assessment of the effectiveness of the implemented UFLS programs as recorded by the information contained in the Planning Coordinator s database. R16 (R10 in current draft) has been revised to clarify the SDT s intent.

12 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. Bob Thomas - Illinois Municipal Electric Agency Andrew Pusztai - ATC No 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 Please see responses to ATCs comments to this question. R1 has been modified to be consistent with the NERC PRC standard. R1 is now applicable to the Planning Coordinator and the phrase in question has been removed. The term forecasted annual peak hour has been replaced with the NERC approved RFC definition of Year One and the NERC definition of Peak Demand based on your concern. R3 has been removed from the standard. The SDT disagrees that capacitor banks are reactors. A new R3, Part 3.1 has been added (and removed from R7) based on your comment. The parenthetical qualifier has been removed from R9 (R6, Part 6.3 in current draft).

13 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 R 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. This R16 wording has been removed because the now approved NERC PRC standard addresses your point. The SDT does not believe the proposed changes add any further clarity to part 9.1. R10 has now been removed since the point is addressed in NERC PRC Table 1 has now been replaced with the generator under-frequency attachment found in NERC PRC and NERC PRC draft. Whether or not the tripping of non-conforming generators affects the effectiveness of the UFLS program is perhaps a relevant question, but such a determination would need to come out of the Planning Coordinator s UFLS assessment and the SDT does not wish to introduce further complexity into this requirement that may well leave Generator Owners in a situation of not knowing up front whether or not they are compliant. Furthermore, the coordination between UFLS program performance criteria and generator tripping has been established in NERC PRC (see Attachment 1 of that standard) predicated on maintaining a reasonable margin between the two sets of characteristic curves in the interest of reliability and the SDT does not wish to entertain

14 exceptions to that margin. 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. R14 has been removed from the standard since it is already covered in the NERC PRC standard. R14 has been removed from the standard since it is already covered in the NERC PRC standard. R14 has been removed from the standard since it is already covered in the NERC PRC standard. The SDT has removed the language may be performed jointly with other Planning Coordinators from R16 (R10 in the current draft) since this is not a requirement. A new R10 Part 10.4 has been added to require the Planning Coordinators assessment to include the effects of neighboring Planning Coordinator areas. The SDT does not believe that current will be confused with current as in amps here, but agrees to make the suggested change. The SDT believes that any disturbance a Planning Coordinator would undertake to simulate in satisfying this sub-requirement is one that would be expected to cause islanding and imbalance.

15 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. The SDT believes both R11 (R7 in current draft) and R17 (R10 in current draft) are applied to two distinct processes and should remain separate requirements. R18 has been removed from the standard since it is already covered in the NERC PRC standard. R18 has been removed from the standard since it is already covered in the NERC PRC standard. R18 has been removed from the standard since it is already covered in the NERC PRC standard. Doug Hohlbaugh - FirstEnergy Corp (Sam Ciccone, Dave Folk) Mike Hurd - DPL Annette Bannon - PPL Lower Mount Bethel Energy, LLC (Mark Heimbach PPL Martins Creek, LLC Elizabeth Davis, PPL Brunner Island, LLC) Brenda Truhe - PPL Electric Utilities Mark Kuras PJM (Albert Dicaprio, William Harm, Patrick Brown, Mark Sims) See response to Question 6 Please see response to question 6. Yes Thank you. Question 2 Time Horizons have been added to the Requirements. Do you agree that the Time Horizons are appropriate for the requirements? If not, please provide specific suggestions. Answers Frequency Yes 8

16 No 1 7 Commenter Answer Comment Response No 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. Patrick O'Loughlin - Buckeye Power, Inc. David Thorne - Potomac Electric Power Company (Alvin Depew, Carl Kinsley) Yes R1 and R2 have been modified and are now applicable to the Planning Coordinator. The Implementation Plan has been modified accordingly. Thank you. Louis Slade Dominion (Michael Yes Thank you. Gildea, Chip Humphrey) Mark Ringhausen ODEC Scott Berry IMPA IMPA has no comment. Thank you. Howard Rulf - We Energies Yes Thank you. Thad Ness - AEP Yes 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. Thank you. R3 has been removed from the standard. Gregory Miller - BGE Yes BGE feels the time horizons are Thank you. appropriate. Jason Marshall - MISO Yes Thank you. Bob Thomas - Illinois Municipal Electric Agency Andrew Pusztai - ATC Yes Doug Hohlbaugh - FirstEnergy Corp See response to Question 6 Please see response to question 6. (Sam Ciccone, Dave Folk) Mike Hurd - DPL Annette Bannon - PPL Lower Mount Bethel Energy, LLC (Mark Heimbach PPL Martins Creek, LLC Elizabeth Davis, PPL Brunner Island, LLC) Brenda Truhe - PPL Electric Utilities Mark Kuras PJM (Albert Dicaprio, William Harm, Patrick Brown, Mark Sims) Yes Thank you. Question 3 The Measures have been modified to include more examples on how to assess performance and outcomes for the purpose

17 of determining compliance with the requirements. Do you agree that the Measures are appropriate? If not, please provide specific suggestions. Answers Frequency Yes 1 No 8 7 Commenter Answer Comment Response Patrick O'Loughlin - Buckeye Power, Inc. David Thorne - Potomac Electric Power Company (Alvin Depew, Carl Kinsley) No 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. Both R3/M3 and R14 have been removed from the standard. Louis Slade Dominion (Michael Gildea, Chip Humphrey) No 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. 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). Mark Ringhausen ODEC No Generally, ODEC has the same comments from the Requirements as for the Measures. Scott Berry IMPA No 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. Howard Rulf - We Energies No In Measurement M12, the word that needs to be inserted after the text Each Generator Owner It is the SDT s intent that the set-points and time delays associated with the tripping of capacitor banks connected to the BES is studied in the assessment. R16.2 (R10, Part 10.2 in current draft) has been modified based on your comment. M10 and R10 have been removed from the standard. The measures for M11 and M12 have not been modified per your request. Please see the responses to your comments regarding the requirements per question 1. Please see the responses to your comments regarding the requirements. R10 and the corresponding M10 have been removed from the standard based on your comment. The SDT agrees and the typos have been fixed.

18 In Measurement M14, the text UFSL needs to be changed to UFLS Thad Ness - AEP No 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 assessmen Gregory Miller - BGE BGE has no comments regarding the modifications to the Measures. Jason Marshall - MISO No We agree with the comments submitted by ATC for this question. Bob Thomas - Illinois Municipal Electric Agency Andrew Pusztai - ATC No 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. The SDT agrees and the typos have been fixed. R3 and the corresponding M3 have been removed from the standard since it is already covered in the NERC PRC standard. Thank you. Please see responses to ATCs comments regarding this question. The SDT agrees and has modified M5 (M4 in the current draft) in accordance with your comment. 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. The SDT agrees and has modified M8 (M6 in the current draft) in accordance with your comment. The SDT agrees and have modified M12 (M8 in the current draft) based on you comment. M14 has been removed from the standard since R14 is covered by the NERC PRC standard Doug Hohlbaugh - FirstEnergy Corp (Sam Ciccone, Dave Folk) Mike Hurd - DPL Annette Bannon - PPL Lower Mount In M15, the wording should be within 45 calendar days to agree with R15. The SDT agrees and has modified M15 (M9 in the current draft) in accordance with your comment. See response to Question 6 Please see response to question 6.

19 Bethel Energy, LLC (Mark Heimbach PPL Martins Creek, LLC Elizabeth Davis, PPL Brunner Island, LLC) Brenda Truhe - PPL Electric Utilities Mark Kuras PJM (Albert Dicaprio, William Harm, Patrick Brown, Mark Sims) Yes Thank you. Question 4 The Violation Severity Levels (VSLs) have been modified to be consistent with the modified requirements and based on NERC and the FERC guidelines. Do you agree that the VSLs are appropriate? If not, please provide specific suggestions. Answers Frequency Yes 3 No 2 11 Commenter Answer Comment Response No The differences in implementation levels between lower, moderate, high and severe are relatively minor and not in accordance with the descriptions. Patrick O'Loughlin - Buckeye Power, Inc. David Thorne - Potomac Electric Power Company (Alvin Depew, Carl Kinsley) Yes Louis Slade Dominion (Michael Gildea, Chip Humphrey) Mark Ringhausen ODEC Scott Berry IMPA IMPA has no comments. Thank you. Howard Rulf - We Energies Yes Thad Ness - AEP 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. The SDT attempted to gradate the VSLs where appropriate to cover all four levels of VSLs. R1 has been modified to apply to the Planning Coordinator. The VSLs have been revised accordingly 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 R3 and the corresponding VSLs have been removed from the standard since it is covered in the NERC PRC-006 Please see response to question 6.

20 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 Gregory Miller - BGE BGE has no comments regarding the modifications to the VSLs. Jason Marshall - MISO Bob Thomas - Illinois Municipal Electric Agency Andrew Pusztai - ATC Doug Hohlbaugh - FirstEnergy Corp (Sam Ciccone, Dave Folk) Mike Hurd - DPL Annette Bannon - PPL Lower Mount Bethel Energy, LLC (Mark Heimbach PPL Martins Creek, LLC Elizabeth Davis, PPL Brunner Island, LLC) Brenda Truhe - PPL Electric Utilities Mark Kuras PJM (Albert Dicaprio, William Harm, Patrick Brown, Mark Sims) The SDT agrees and have modified the VSL for R12 (R8 in current draft) in accordance with your comment. Thank you. See response to Question 6 Please see response to question 6. Yes Thank you. Question 5 The Violation Risk Factors (VRFs) have been modified to be consistent with the modified requirements and based on NERC and the FERC guidelines. Do you agree that the VRFs are appropriate? If not, please provide specific suggestions. Answers Frequency Yes 8 No 0 8 Commenter Answer Comment Response Patrick O'Loughlin - Buckeye Power, Yes Thank you. Inc. David Thorne - Potomac Electric Yes Thank you. Power Company (Alvin Depew, Carl Kinsley) Louis Slade Dominion (Michael Gildea, Chip Humphrey) Mark Ringhausen - ODEC Scott Berry IMPA IMPA has no comments. Thank you.

21 Howard Rulf - We Energies Yes Thad Ness - AEP Yes Gregory Miller - BGE BGE has no comments regarding the Thank you. modifications to the VRFs. Jason Marshall - MISO Yes Bob Thomas - Illinois Municipal Electric Agency Andrew Pusztai - ATC Yes Doug Hohlbaugh - FirstEnergy Corp See response to Question 6 Please see response to question 6. (Sam Ciccone, Dave Folk) Mike Hurd - DPL Annette Bannon - PPL Lower Mount Yes Thank you. Bethel Energy, LLC (Mark Heimbach PPL Martins Creek, LLC Elizabeth Davis, PPL Brunner Island, LLC) Brenda Truhe - PPL Electric Utilities Mark Kuras PJM (Albert Dicaprio, William Harm, Patrick Brown, Mark Sims) Yes Thank you. Question 6 The Standard Drafting Team believes the standard is ready for Category Ballot. Do you agree? If not, please provide specific suggestions that would make it acceptable to you. Answers Frequency Yes 0 No 15 1 Commenter Answer Comment Response Patrick O'Loughlin - Buckeye Power, No See previous comments Please see previous responses. Inc. David Thorne - Potomac Electric No See responses above Please see responses above. Power Company (Alvin Depew, Carl Kinsley) Louis Slade Dominion (Michael No No, for reasons indicated in responses to Please see responses to question 1. Gildea, Chip Humphrey) question 1. Mark Ringhausen - ODEC 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 The majority of the UFLS SDT believes the

22 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 ). PRC-006-RFC-01 standard is still needed for reliability since it goes beyond, adds detail and covers matters not required by the NERC PRC standard. Furthermore, the old NERC PRC standard remains in effect until the mandatory effective date of the NERC PRC standard. 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. ODEC does not believe that developing a regional standard is the proper method for the Planning Coordinators to develop their UFLS program. Third, the RFC ULFS draft standard does not follow the PRC Applicability section correctly. PRC applies to Planning Coordinators, UFLS entities (Transmission Owners and Distributions 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 Coordinators. 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 R1 and R2 have now been reassigned to the Planning Coordinators as boundaries for the setting of UFLS program parameters. This standard will, therefore, not become a substitute for Planning Coordinators required UFLS programs. The RFC UFLS draft standard has now, since the last comment period, been coordinated with NERC PRC and applicability to UFLS entities in the NERC standard should not cause a conflict in the RFC standard.

23 might be a registration issue, but a standard cannot fix registration issues. Currently in place in many Midwest states, the UFLS is performed at the transmission level and not the distribution level with tariff agreements in place. The use of UFLS entities would help in keeping these tariff agreements in place. Last, in requirement 12.1 and its subrequirements, 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 that is not justified by any small increase in reliability of the BES. 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 would be armed to trip, so, those relay settings would need to be changed when the unit was off-line. Third, there may not be a third party willing to offer compensatory services in the local geographically area to a generator that would keep the area balanced for islanding areas. The complexity of a UFLS program that would have to track the status of nonconforming generators is staggering. For instance, in order to protect the granularity The SDT continues to believe that most Generator Owners should be able to conform trip settings of their units to the criteria without substantial investments. (Note: Table 1 has now been replaced with the generator underfrequency attachments found in NERC PRC and NERC PRC draft.) Where Generator Owners are unable to conform trip settings to the criteria, the SDT continues to maintain in the interest of fairness not to burden Distribution Providers with an obligation to cover these generators, but to require compensatory load shedding by the Generator Owner. Whether the impact on BES reliability of nonconforming generators is small or large is not an answer the SDT can predict or determine and there may well be situations involving islands where the reliability impact is large. The SDT agrees that maintaining a compensatory load shedding scheme according to the hour-by-hour dispatch or status of a nonconforming generator is unrealistic. All that is required is that the compensatory load shedding be equal to or greater than the generator s dispatch.

24 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 the 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 illconceived 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 and has not required compensatory load shedding for nonconforming generators. This RFC Standard does not require this either. Scott Berry - IMPA 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