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Scott Berry

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Indiana Municipal Power Agency

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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?


1) If not, please provide specific suggestions.

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.)

2) Time Horizons have been added to the Requirements. Do you agree that the Time Horizons are appropriate for the requirements?


2) If not, please provide specific suggestions.


3) The Measures have been modified to include more examples on how to assess performance and outcomes for the purpose of determining compliance with the requirements.  Do you agree that the Measures are appropriate?


3) If not, please provide specific suggestions.

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.

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?


4) If not, please provide specific suggestions.

IMPA has no comment.

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?


5) If not, please provide specific suggestions.

IMPA has no comments.

6) The Standard Drafting Team believes the standard is ready for Category Ballot.  Do you agree?


6) If not, please provide specific suggestions that would make it acceptable to you.

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.

Created at 9/7/2012 10:09 AM by System Account
Last modified at 9/7/2012 10:09 AM by System Account