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2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls | BAL-005-1, BAL-006-3 & FAC-001-3

Description:

Start Date: 07/30/2015
End Date: 09/14/2015

Associated Ballots:

Ballot Name Project Standard Pool Open Pool Close Voting Start Voting End
2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls BAL-005-1, BAL-006-3 & FAC-001-3 IN 1 ST 2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls BAL-005-1, BAL-006-3 & FAC-001-3 07/30/2015 08/28/2015 09/04/2015 09/14/2015
2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls BAL-005-1, BAL-006-3 & FAC-001-3 Non-binding Poll IN 1 NB 2010-14.2.1 Phase 2 of Balancing Authority Reliability-based Controls BAL-005-1, BAL-006-3 & FAC-001-3 Non-binding Poll 07/31/2015 08/28/2015 09/04/2015 09/14/2015

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Hot Answers

Erika Doot, On Behalf of: Erika Doot, , Segments 1, 5

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The added sentence at the end of the definition adequately serves the purpose of clarifying that all “resources” are included rather than just traditional generators.  The change to add the descriptor “Centrally located” when describing the “equipment” is also problematic.  There does not appear to be a stated justification for making that change and it could introduce issues in interpretation surrounding redundant systems or sub-systems that could or should be included in the system that is used for AGC.  If there is a reason for continuing to include the “centrally located” descriptor, we suggest that the SDT clarify the reason.

SPP Standards Review Group, Segment(s) , 9/14/2015

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Other Answers

John Fontenot, 8/10/2015

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Andrew Pusztai, 9/4/2015

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Nick Vtyurin, On Behalf of: Manitoba Hydro - MRO - Segments 1, 3, 5, 6

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Thomas Foltz, AEP, 5, 9/8/2015

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Dominion, Segment(s) 5, 6, 1, 3, 9/9/2015

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The California ISO supports the comments of the ISO/RTO Council Standards Review Committee for all questions in this Survey.

Richard Vine, 9/9/2015

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Jeremy Voll, Basin Electric Power Cooperative, 3, 9/9/2015

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Jeri Freimuth, 9/9/2015

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Leonard Kula, Independent Electricity System Operator, 2, 9/9/2015

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We agree it makes AGC more inclusive and understand there was a FERC directive to make this change, but the directive does not add to reliability.

MRO-NERC Standards Review Forum (NSRF), Segment(s) 3, 4, 5, 6, 1, 2, 9/9/2015

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Terry BIlke, 9/10/2015

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Amy Casuscelli, On Behalf of: Xcel Energy, Inc. - MRO, WECC, SPP RE - Segments 1, 3, 5, 6

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Chris Mattson, 9/10/2015

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Southern Company, Segment(s) 1, 6, 3, 5, 4/13/2015

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Eleanor Ewry, On Behalf of: Puget Sound Energy, Inc., WECC, Segments 1, 3, 5

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We agree that the modified definition is a step in the right direction.  However, the definition references Demand Response in capital letters.  While that concept is recognized by industry, it officially is not a NERC Glossary Term.  We recommend that SDT rephrase the last sentence of this definition to read “Resources utilized under AGC may include, but not be limited to, conventional generation, variable energy resources, energy storage devices, and demand response resources.”

ACES Standards Collaborators, Segment(s) 1, 3, 5, 6, 4, 9/11/2015

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Jonathan Appelbaum, 9/13/2015

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Texas RE does agree that the revised definition is more inclusive.    There is a concern, however, about disregarding asynchronous Tie MWs in the calculation for Reporting ACE.  If a Balancing Authority (BA) has 1000 MWs of generation and 500 MWS of load with the remaining generation being transferred asynchronously, how will the ACE equation , and subsequently AGC,  work properly?   

 

With the revised definition of Reporting ACE, it appears the Standard Drafting Team (SDT) is disregarding single BA Interconnections, such as ERCOT and Quebec.  Texas RE is concerned about the statement “All NERC Interconnections with multiple Balancing Authority Areas operate using the principles of Tie-bias (TLB) Control and requirement the use of an ACE equation similar to the Reporting ACE defined above.”  This statement implies that single BA Interconnections, such as ERCOT and Quebec do not operate using the principles of TLB and the use of ACE.  If not, how does BAL-001 apply?  Is indicating an “alternative” method for a Reporting ACE equation use advocating regional differences?

 

Texas RE inquires as to whether it is the SDT’s intent that AGC (as currently defined in the proposed definition) will be only frequency-based for single-balancing authority areas.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 9/14/2015

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Bob Thomas, 9/14/2015

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John Fontenot, 9/14/2015

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John Fontenot, 9/14/2015

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John Fontenot, 9/14/2015

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David Jendras, Ameren - Ameren Services, 3, 9/14/2015

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FMPA supports using the term resources to make the definition more inclusive, but the capitalized term Demand Response is not in the NERC glossary of terms.

FMPA, Segment(s) , 7/9/2015

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Scott McGough, Georgia System Operations Corporation, 3, 9/14/2015

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PJM finds that the modified definition of AGC is inclusive of more resource types than only traditional generation resources. However, AGC equipment does not directly adjust the output of resources, but instead generates and sends control signals to the resources to change output. PJM suggests the following change to the definition for clarity:

Automatic Generation Control (AGC): Centrally located equipment that generates and sends control signals to automatically adjusts resources in a Balancing Authority Area to help maintain the Reporting ACE in that of a Balancing Authority Area within the bounds required by applicable NERC Reliability Standards. Resources utilized under AGC may include, but are not limited to, conventional generation, variable energy resources, storage devices and loads acting as resources (such as Demand Response).

Mark Holman, 9/14/2015

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AGC is no longer used in BAL-005-1,  therefore HQ questions whether Project 2010-14.2.1 is the best opportunity to revise this definition.

Chantal Mazza, On Behalf of: Hydro-Qu?bec TransEnergie - NPCC - Segments 2

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The modification is on the correct track to expand the definition.

Theresa Rakowsky, 9/14/2015

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Duke Energy recommends that the drafting team clarify or state that just because a term appears in a definition does not make the definition applicable to said term. For example, the term “Demand Response” appears in the proposed definition of Automatic Generation Control (AGC), however, AGC  does not adjust Demand Response. Clarification is needed from the drafting team stating that just because this term appears in the definition, this doesn’t mean every type of Generating Resource, Load Resource, or Load reacting as a resource is capable of providing response to an AGC signal. Just because a term is listed in the definition, doesn’t mean it should qualify as an example. We suggest the drafting team revise the language to include “such as qualified demand resources” rather than “Demand Response” which can mean a lot of different things.

Duke Energy , Segment(s) 1, 5, 6, 4/10/2014

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Andrea Basinski, 9/14/2015

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These comments are submitted on behalf LG&E and KU Energy, LLC (LG&E/KU).  LG&E/KU is registered in the SERC Region for one or more of the following NERC functions: BA, DP, GO, GOP, IA, LSE, PA, RP, TO, TOP, TP, and TSP

Comments:

Making a definition “more inclusive” does not make it clearer or better.  In fact, an argument can be made that an “inclusive” definition can become problematic.  The proposed definition includes uneccessary, prescriptive language on what types of resources may be used for AGC.  We are concerned that the list will raise expectations that VERs, storage devices and Demand Response resources should be included in an entity’s AGC function.  Many Demand Response programs (such as residential load interruption) are not compatible with AGC operations and should not be considered as such.

The last sentence of the proposed definition is not necessary, reduces the clarity of the definition  and should be deleted.

Automatic Generation Control (AGC): Centrally located equipment that generates and sends control signals to automatically adjust resources in a Balancing Authority Area to help maintain the Reporting ACE in that of a Balancing Authority Area within the bounds required by applicable NERC Reliability Standards.

LG&E and KU Energy, LLC, Segment(s) 1, 3, 5, 6, 9/11/2015

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Douglas Webb, 9/14/2015

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Matthew Beilfuss, On Behalf of: WEC Energy Group, Inc., MRO, RF, Segments 3, 4, 5, 6

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The use of centrally located equipment, that automatically adjusts, maintain Reporting ACE, resources utilized under AGC needs to be considered. 

There is no justification to link the definition of Automatic Generation Control (AGC) to a given location.

AGC is not hardware (equipment); AGC is software.

AGC does not “adjust resources” (that is usually accomplished at the resource itself). AGC “is used to adjust resources”.

AGC is not designed for reporting purposes. AGC is design to assist in the control of a BA’s balance of its resources to its NERC mandated balancing obligations.

Propose that the definition be revised to:

Automatic Generation Control (AGC): Software designed and used to adjust a Balancing Authority’s resources to meet the BA’s balancing requirements as required by applicable NERC Reliability Standards.

BAL-005 being a NERC standard and not one of the many regionally-approved standards is applicable to all BAs unless the BA is in a region in which the standard is superseded by a FERC-approved regional standard. Automatic Time Error Correction is not a part of the FERC-approved standards for all BAs. For clarity the regionally-approved definition and references to Automatic Time Error Correction (I ATEC) be deleted and left to an approved regional standard.

 

 

NPCC--Project 2010-14.2.1 Phase 2 of Bal Auth Rel-based Controls - BAL-005-1, BAL-006-3, FAC-001-3 , Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 9/14/2015

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Jason Snodgrass, 9/14/2015

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Mike ONeil, NextEra Energy - Florida Power and Light Co., 1, 9/14/2015

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Payam Farahbakhsh, Hydro One Networks, Inc., 1, 9/14/2015

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The SRC does not agree with the proposed definition of AGC.

 

The SRC recommends the following definition for AGC:

Automatic Generation Control (AGC): A process designed and used to adjust a Balancing Authority’s resources to meet the BA’s balancing requirements as required by applicable NERC Reliability Standards.

 

See attached for the full text of the comments to Questions 1-6

ISO Standards Review Committee, Segment(s) 2, 9/14/2015

SRC - 2010-14-2-1 BAL-005.006 FAC-001.docx

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Andrea Jessup, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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Colorado Springs Utilities, Segment(s) 1, 6, 3, 5, 9/14/2015

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Hot Answers

Reclamation recommends that the drafting team propose to retire BAL-005-0.2b R1 instead of moving the requirement into FAC-001-3.  Reclamation does not believe that the drafting team has addressed the Periodic Review Team’s recommendation to identify “what is needed for ensuring facilities are within a Balancing Authority Area prior to MW being generated or consumed.”  Like the existing requirement, the proposed requirement does not mention verifying that facilities are within the metered boundaries of a Balancing Authority Area “prior to transmission operation, resource operation, or load being served.”  Therefore, the proposed requirement perpetuates a paperwork burden that costs staff time and resources of Generator Operators, Transmission Operators, and Load Serving Entities with longstanding arrangements with their host Balancing Authority.  Registered Entities acquiring letters to confirm that they are in the metered boundaries of a Balancing Authority Area provides no benefit to system reliability.

Erika Doot, On Behalf of: Erika Doot, , Segments 1, 5

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These requirements do not rise to the level of needing a continuously audited Reliability Standard.  Once a facility is interconnected and certified, then the inclusion within a BA’s metered bounds should be verified at that time.  There should not be a need for continuing certification that it remains within the metered bounds.  The requirements as stated only result in administrative efforts and are an exercise in submitting attestations.

 

One suggestion would be to simply add a sub-requirement that the Transmission Owner’s Interconnection Requirements (FAC-001-3 R1) must include a requirement that all interconnected facilities must be demonstrated to be within a Balancing Authority’s metered boundaries.   Then there would be no need for the new, proposed R5-R7.  This puts the compliance effort into ensuring the facility is metered properly upon interconnection – to satisfy the TO Facility Interconnection Requirements – rather than an ongoing verification that the facilities continue to be within the metered bounds.

SPP Standards Review Group, Segment(s) , 9/14/2015

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Other Answers

John Fontenot, 8/10/2015

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Andrew Pusztai, 9/4/2015

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Nick Vtyurin, On Behalf of: Manitoba Hydro - MRO - Segments 1, 3, 5, 6

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We do not agree that FAC-001 is the correct standard to house these obligations.  FAC-001 applies to the interconnection of new facilities, while the R5, R6 & R7 Requirements taken from BAL-005-0.2b apply to all Transmission, Generation & Load facilities. 

In the event that the drafting team *is* successful in moving these obligations to FAC-001, the new requirements will need to be clarified so that the requirements apply only to new interconnecting facilities (consistent with the spirit of the other FAC-001 requirements). In that case, separate requirements will still be required elsewhere to apply to existing Transmission, Generation & Load facilities. In addition, it would also be incumbent on the TO to ensure that the wording for these obligations are explicit within their interconnect agreements and the necessary interconnect guides that are specified in FAC-001.

AEP’s decision to vote negative on this proposal is driven by these objections.

Thomas Foltz, AEP, 5, 9/8/2015

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Dominion, Segment(s) 5, 6, 1, 3, 9/9/2015

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Richard Vine, 9/9/2015

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It is not necessary to move this requirement. The SDT is taking a flawed requirement and moving it to another location.  The requirement should be improved as follows.

R1.      All generation, transmission, and load operating within an Interconnection must be included within the metered boundaries of a Balancing Authority Area.

 

The requirement above was a concept (Control Area Criteria) that was swept into the V0 standard.  The only way to prove that everything is within the metered bounds of a BA is via Inadvertent Interchange accounting.  R1 should be kept as-is, the sub-bullets removed and the measure for R1 should be:

M1.  The Balancing Authority was unable to agree with an Adjacent Balancing Authority when performing Inadvertent Interchange accounting and it was found that the Balancing Authority had an error in its model or tie lines that misstated its Net Actual Interchange value in its Inadvertent Interchange accounting. 

Jeremy Voll, Basin Electric Power Cooperative, 3, 9/9/2015

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Jeri Freimuth, 9/9/2015

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Leonard Kula, Independent Electricity System Operator, 2, 9/9/2015

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See attachment with strikethrough.

It is not necessary to move this requirement. The SDT is taking a flawed requirement and moving it to another location.  The requirement should be improved as follows.

R1.      All generation, transmission, and load operating within an Interconnection must be included within the metered boundaries of a Balancing Authority Area.

R1.1. Each Generator Operator with generation facilities operating in an Interconnection shall ensure that those generation facilities are included within the metered boundaries of a Balancing Authority Area.

R1.2. Each Transmission Operator with transmission facilities operating in an Interconnection shall ensure that those transmission facilities are included within the metered boundaries of a Balancing Authority Area.

R1.3. Each Load-Serving Entity with load operating in an Interconnection shall ensure that those loads are included within the metered boundaries of a Balancing Authority Area.

The requirement above was a concept (Control Area Criteria) that was swept into the V0 standard.  The only way to prove that everything is within the metered bounds of a BA is via Inadvertent Interchange accounting.  R1 should be kept as-is, the sub-bullets removed and the measure for R1 should be:

M1.  The Balancing Authority was unable to agree with an Adjacent Balancing Authority when performing Inadvertent Interchange accounting and it was found that the Balancing Authority had an error in its model or tie lines that misstated its Net Actual Interchange value in its Inadvertent Interchange accounting. 

MRO-NERC Standards Review Forum (NSRF), Segment(s) 3, 4, 5, 6, 1, 2, 9/9/2015

Project 2010-14..2.docx

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It is not necessary to move this requirement. The requirement can be improved by keeping it where it is and limiting it to:

R1.      All generation, transmission, and load operating within an Interconnection must be included within the metered boundaries of a Balancing Authority Area.

The requirement is a concept from the NERC Operating Manual (Control Area Criteria) that was swept into the V0 standard.  There is only one way to prove that everything is within the metered bounds of a BA, that is through Inadvertent Interchange accounting.  Thus the measure for this requirement should be:

M1.  The Balancing Authority was unable to agree with an Adjacent Balancing Authority when performing Inadvertent Interchange accounting and it was found that the Balancing Authority had an error in its model or tie lines that misstated its Net Actual Interchange value in its Inadvertent Interchange accounting. 

Terry BIlke, 9/10/2015

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BAL-005-0.2b R1 should remain where it is, but would be improved by the removal of the sub Requirements.  The only means to prove that everything is within the metered boudaries of a Balancing Authority is through Inadventent Interchange accounting.

The revised R1 should read:  R1.      All generation, transmission, and load operating within an Interconnection must be included within the metered boundaries of a Balancing Authority Area.
The measure M1 should read:  M1.  The Balancing Authority was unable to agree with an Adjacent Balancing Authority when performing Inadvertent Interchange accounting and it was found that the Balancing Authority had an error in its model or tie lines that misstate its Nets Actual Interchange value in its Inadventent Interchange accounting.
 

Amy Casuscelli, On Behalf of: Xcel Energy, Inc. - MRO, WECC, SPP RE - Segments 1, 3, 5, 6

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Chris Mattson, 9/10/2015

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While there is agreement with the removal of R1 from BAL-005-0.2b, the insertion of 4.1.3, and R5-R7 into FAC-001-2 is not required.  Notification of an entities inclusion within a Balancing Authority’s metered boundaries can be accomplished through the NERC Rules of Procedure, Section 500,  FAC-001-2, proposed standard TOP-003-3 and existing standard IRO-010-2.  For example, sufficient latitude exists within FAC-001-2 as approved,  for the TO to provide  notification to “those responsible for the reliability of the affected system(s) of new or materially modified existing interconnections.”  Through this requirement, the TO  can provide a list of new or modified facilities (such as new or modified load, transmission and generator connections)  to the TOP, BA and RC.

Southern Company, Segment(s) 1, 6, 3, 5, 4/13/2015

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As worded, we do not believe these requirements are appropriate for FAC-001-3.  Since FAC-001-3 applies to documented Facility interconnection requirements, it would be more appropriate to require that the documented interconnection requirements contain language stating that transmission, generation and end-user interconnected Facilities must be located within the Balancing Authority Area’s metered boundaries.  This could be accomplished by adding R3.3 stating “Procedures for ensuring that transmission Facilities, generation Facilities and end-user Facilities are within the Balancing Authority Area’s metered boundaries.”  The requirement to verify that existing facilities are located with the metered boundaries of a Balancing Authority Area is most appropriately assigned to the TOP, and not to the TO, GO and the LSE.

Eleanor Ewry, On Behalf of: Puget Sound Energy, Inc., WECC, Segments 1, 3, 5

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  1. We concur that the intent of BAL-005-0.2b Requirement R1 provides for identification of Interconnection Facilities and not for the calculation of Reporting ACE.  We question if the SDT followed the recommendations of the Project 2010-14.2 BAL Standards PRT to “explore if the role of the TOP would appropriately cover the loads interconnected to that TOP such that the LSE requirement may not be necessary.”  We ask the SDT to provide rationale for the proposed FAC-001-3 standard to explain their conclusion on why they continue to list the LSE as an applicable entity.  We remind the SDT that the retirement of the LSE is pending FERC approval through the Risk-Based Registration (RBR) initiative.  We do not understand why the SDT feels like the LSE has a reliability role, when the ERO continues to argue that the LSE is primarily focused on commercial activities and other entities, such as the TOP, would continue to meet reliability needs without the LSE.  We strongly recommend that the drafting team remove the LSE from the applicability section.
  2. As listed within this project’s SAR, the Project 2010-14.2 BAL Standards PRT “believes that the requirements to identify the applicable BA should perhaps be in the interconnection agreements (via FERC’s OATT or NAESB, for example),” we believe these requirements already do.  Many other reliability requirements in the TOP and IRO standards support the identification of Interconnection Facilities through data modeling and specifications.  For example, TOP-003-3 R4 identifies that “each Balancing Authority shall distribute its data specification to entities that have data required by the Balancing Authority’s analysis functions and Real‐time monitoring.”  If a BA needs information regarding a particular load, generation resource, or transmission line operating within its BA Area, based on this requirement, would they not “identify” the correct entity to send their specification?  Furthermore, NERC has spent significant time and resources on the development of the BES definition and the removal of the LSE from its functional model.  These efforts were accomplished to focus on entities and facilities that posed a significant risk to BES reliability.  The SDT has already identified that the intent of these requirements is not for the calculation of Reporting ACE and only the identification of entities.  Moreover, if a generation resource, transmission line, or load is not properly accounted for in the calculation of Reporting ACE, Inadvertent Interchange will result and the BA would investigate to correct the discrepancy, as a best practice, accordingly.  We recommend the SDT remove these requirements from the proposed draft standards.

ACES Standards Collaborators, Segment(s) 1, 3, 5, 6, 4, 9/11/2015

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First, a quick review of the Standards shows there is no other specific requirement to ensure a facility is in a metered boundry or telemtery is provided to a RC, BA, or TOP.  This requirement is to ensure that a load or generator is metered and communicated to BA for BA function.  It is just as important that line metering is reported to TOP and RC, yet there is no FAC requirement to install metering and telemetry.  For TOP and RC, there is TOP-03 and IRO-010 with a data specification and process to deliver data.

Second, FAC-001 is about developing a single document for one-time use by an interconnecting entity to know what is required to complete an interconnection. The proposed change creates an ongoing requirement to confoirm that the interconection is in the metered boundaries ofthe BA.  The proposed requirement is not consistenent with FAC-001.  A consistent approach to FAC-001 is to require that the requirements address the metering required to facilitate the BA function, but this is already impleied in the current FAC-001-2 standard.

Balancing is becoming a complicated function as compared to the Version 0 days.  The BA should have its own data specification standard similar to TOP-003 or IRO-010.  In the alternative these requirements should be retired, with the comment thatthe requirement is implied already in FAc-001-2 and the Technical and Guideline section of FAC-001-2 will be updated to include a specific explanation of including interconnection in BA metered boundary.

Jonathan Appelbaum, 9/13/2015

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Texas RE noticed that the Load-Serving Entity (LSE) function was added to the FAC-001-3 applicability but is not mentioned in the Evidence Retention section.

 

Texas RE noticed the term, “Transmission Facilities” is capitalized in R5 but not in R1.2.  The term “Transmission Facilities” is not a defined term in the NERC glossary so it could cause confusion if capitalized.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 9/14/2015

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Given the stongly suppported rationale for deactivating the LSE registration function under the Risk-Based Registration initiative, Requirement 1.3 of BAL-005-0.2b should not be moved to FAC-001-3 as Requirement 7.  The necessity of retaining this language for reliability purposes should be reconsidered.  [Has there ever been a situation where Load was not within a BA metered boundary?]  If this language is needed for reliability, an alternate functional entity should be identified.

Bob Thomas, 9/14/2015

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John Fontenot, 9/14/2015

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John Fontenot, 9/14/2015

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John Fontenot, 9/14/2015

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Ameren supports MISO's comments for this question

David Jendras, Ameren - Ameren Services, 3, 9/14/2015

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FMPA believes these requirements should be retired on the basis that they are covered by the data specification requirements of Board approved TOP-003-3. While it may be appropriate to include the concept of meters and BA metered boundaries in Facility interconnection requirements, as currently worded the proposed requirements do not fit with the purpose or applicability of FAC-001.

FMPA, Segment(s) , 7/9/2015

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Scott McGough, Georgia System Operations Corporation, 3, 9/14/2015

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With moving BAL-005-0.2b R1 to FAC-001 R5 and R6, the requirement has shifted from being a Generator and Transmission Operator function to a Generator and Transmission Owner function. PJM questions and considers consequences with this change. PJM seeks clarity on the following topics:

Generation Owners, Transmission Owners, and Load-Serving Entities have no requirement to supply the Balancing Authority with data that affects the ACE calculation. PJM proposes the following changes to FAC-001 R5, R6, and R7:

R5. Each Transmission Owner with transmission Facilities operating in an Interconnection shall confirm that each transmission Facility is within a Balancing Authority Area’s metered boundaries. The Transmission Owner shall coordinate any changes caused to the ACE due to each transmission Facility with the impacted Balancing Authorities. 
R6. Each Generator Owner with generation Facilities operating in an Interconnection shall confirm that each generation Facility is within a Balancing Authority Area’s metered boundaries. The Generation Owner shall coordinate any changes caused to the ACE due to each generation Facility with impacted Balancing Authorities.
R7. Each Load-Serving Entity with Load operating in an Interconnection shall confirm that each Load is within a Balancing Authority Area’s metered boundaries. The Load-Serving Entity shall coordinate changes caused to the ACE due to each Load with impacted Balancing Authorities.

Since Reporting ACE is made up of many components, including Net Actual Interchange (NIA), Balancing Authorities will be dependent on the Generator Owners, Transmission Owners, and Load-Serving Entities for this data. When ACE is impacted by the identified Interconnection Facilities, how should Reporting ACE be addressed by the Balancing Authority or Reliability Coordinator? If a Generator, Transmission Owner, or load-Serving Entity fail to confirm that each of their Facilities are within the Balancing Authority Area’s metered boundaries, is the affected Balancing Authority responsible for calculating an accurate Reporting ACE?

What effects will this have on R5? Will the Balancing Authority be aware data from the Generator Owner or Transmission Owner are missing or invalid if the Generator Owner or Transmission Owner have not confirmed it?

Mark Holman, 9/14/2015

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FAC-001 is about Facility Interconnection Requirements.  In the application guidelines of FAC-001-2, it is mentioned that these requirements include metering and telecommunications and as such could be interpreted to already include a requirement of metering to the BA.  Meeting of facility interconnection requirements however is the purpose of FAC-002-1.

Therefore 2 options are available:

  1. Modify the purpose of FAC-001 to include the GO, TO and LSE,DP or end-user meeting with facility interconnection requirements (whereas presently the purpose is only to make these requirements available) and add in section B, requirements for the GO, TO and LSE,DP or end-user to comply with all requirements set out in R1 thru R4 (not only with the requirement of being within a BA’s metered boundaries as is the case with Project 2010-14.2.1 proposal). Revise purpose of FAC-002-1 so that it addresses coordination studies rather than meeting facility connection and performance requirements.
  2. Change the title of FAC-002 which presently is a bit at odds with its purpose and add requirements for the GO, TO and LSE,DP or end-user to comply with all requirements set out in FAC-001.

Chantal Mazza, On Behalf of: Hydro-Qu?bec TransEnergie - NPCC - Segments 2

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As worded, we do not believe these requirements are appropriate for FAC-001-3.  Since FAC-001-3 applies to documented Facility interconnection requirements, it would be more appropriate to require that the documented interconnection requirements contain language stating that transmission, generation and end-user interconnected Facilities must be located within the Balancing Authority Area’s metered boundaries.  This could be accomplished by adding R3.3 stating “Procedures for ensuring that transmission Facilities, generation Facilities and end-user Facilities are within the Balancing Authority Area’s metered boundaries.”  The requirement to verify that existing facilities are located with the metered boundaries of a Balancing Authority Area is most appropriately assigned to the TOP, and not to the TO, GO and the LSE.

Theresa Rakowsky, 9/14/2015

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Duke Energy requests further clarification on how the drafting team anticipates an entity will be required to demonstrate compliance with R5. As written, it does not appear that the proposed Requirements and Measures are in alignment. Currently, the requirements state that an entity (TO, GO, LSE) must confirm that a Facility is within a Balancing Authority Area’s Metered Boundary, however, the measure suggests that an entity should point to a procedure to demonstrate compliance with R5, R6, and R7. We suggest that the drafting team revise the Measures to better align with what is being asked in the requirements, perhaps stating that an attestation letter from the BA would be adequate to demonstrate confirmation that an entity’s Facility is within a BA Area’s Metered Boundary.

Duke Energy , Segment(s) 1, 5, 6, 4/10/2014

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As worded, we do not believe  that BAL-005-0.2b Requirement R1 is appropriate for FAC-001-3.  Since FAC-001-3 applies to documented Facility interconnection requirements, it would be more appropriate to require that the documented interconnection requirements contain language stating that transmission, generation and end-user interconnected Facilities must be located within the Balancing Authority Area’s metered boundaries.  This could be accomplished by adding R3.3 stating “Procedures for ensuring that transmission Facilities, generation Facilities and end-user Facilities are within the Balancing Authority Area’s metered boundaries.”  The requirement to verify that existing facilities are located with the metered boundaries of a Balancing Authority Area is most appropriately assigned to the TOP, and not to the TO, GO and the LSE.

Andrea Basinski, 9/14/2015

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LG&E and KU Energy, LLC, Segment(s) 1, 3, 5, 6, 9/11/2015

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KCP&L believes moving BAL-005-02.b R1 to FAC-001 should be rejected; it is an attempt to shoe-horn Requirements into an unrelated Standard, or, at best, marginally related Standard.

The FAC-001 Standard relates to entities seeking to interconnect with the Bulk Electric System. The Proposed FAC-001-3 and its predecessor versions’ Purpose declaration state, "To avoid adverse impacts on the reliability of the Bulk Electric System, Transmission Owners and applicable Generator Owners must document and make Facility interconnection requirements available so that entities seeking to interconnect will have the necessary information."

It is unclear how Transmission Owners, Generation Owners, and Load-Serving Entities confirming they are within a Balancing Authority’s metered boundaries relate to Generator Owners seeking interconnection with the Bulk Electric System. The FAC-001 Standard relates to new equipment planned to interconnect with the Bulk Electric System while BAL-005-02.b R1 relates to current and operational interconnections.

Additionally, the SAR discusses moving the TOP, LSE, and GOP from BAL-005-02.b (See SAR, pp. 4-5) to the FAC Standards. It is unclear where the TOP duties under R1 landed. It didn’t land in FAC-001. Granted, the SAR is a framework and not binding, the language suggests the SDT was uncertain where to "put" the R1 Requirement. However, the Proposed FAC-001-3 R5 Violation Severity Level states, "The Transmission Operators with Transmission Facilities operating in an Interconnection…" In consideration of the VSL language and the proposed FAC-001-3 not expressly applicable to Transmission Operators, KCP&L is concerned that moving BAL-005-02.b R1 to FAC-001, creates an unstated duty for Transmission Operators.

Furthermore, the Proposed FAC-001-3 Purpose declaration is reiterated in Applicability Sec. 4.1.2.1., "Generator Owner with a fully executed Agreement to conduct a study on the reliability impact of interconnecting a third party Facility to the Generator Owner’s existing Facility that is used to interconnect to the Transmission system."

The FAC-001 Standard relates to new interconnects to the Bulk Electric System and should not be used as a landing pad for BAL-005 Requirements that no longer are relevant to BAL-005. KCP&L does not object to moving BAL-005 R1 to another Standard, but FAC-001 is not the appropriate Standard and the proposed changes should be reconsidered.

Finally, in the event the changes to FAC-001-3 R5, R6, and R7 are endorsed by the stakeholders, KCP&L would ask language be added to FAC-001-3 to highlight it is applicable to new facilities, including the facilities identified in R5, R6, and R7.

Douglas Webb, 9/14/2015

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We agree with moving BAL-005-0.2b Requirement R1 to FAC-001 standard.  However, given the likely retirement of the LSE functional role consideration should be given in the SAR to making the requirement applicable to the DP functional entity role.

Matthew Beilfuss, On Behalf of: WEC Energy Group, Inc., MRO, RF, Segments 3, 4, 5, 6

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Load Serving Entity (LSE) function:  NERC provided FERC with justification to retire BAL-005-0.2b Part R1.3 for the LSE function (LSE function deregistration).  Adding LSE requirements to FAC-001 does not appear to align with NERC’s justification and the intent to retire BAL-005-0.2b R1.3.

FAC-001 Table of Compliance Elements: R5 and R6 reference Transmission Operator and Generation Operator, instead of Transmission Owner and Generator Owner.

The Purpose of FAC-001 is to “…make Facility interconnection requirements available so that entities seeking to interconnect will have the necessary information.”  Adding requirements to FAC-001 regarding metered boundaries appears to be misplaced.  The proposed additions are ongoing requirements to confirm the metering of transmission facilities.  The use of the word “confirm” is not the same as to establish the interconnection requirements.

NPCC--Project 2010-14.2.1 Phase 2 of Bal Auth Rel-based Controls - BAL-005-1, BAL-006-3, FAC-001-3 , Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 9/14/2015

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(1)   FAC-001-2 was revised in 2013 to eliminate any requirements that were not necessary for reliability according to FERC paragraph 81 directions. As a member of the FAC-001-2 SDT charged with this task, GTC along with the other members followed the directives of FERC and retained only the requirements necessary for system reliability. As such 14 sub-requirements in FAC -001 were removed including a requirement for metering and telecommunication.

 Although GTC sees a merit in ensuring that the Area Control Error is calculated properly, GTC believes that the proposed requirements (FAC-001-3-R5, R6 and R7) does not resolve or address a reliability concern and would violate paragraph 81 criteria.

Moreover GTC believe that requirements FAC-001-3-R5, R6 and R7 address specific needs for operating the system and therefore belong and already are included in Operations Standards such as TOP and IRO and not a Planning Standard associated with Facility interconnection Requirements. 

 

(2)   As listed within this project’s SAR, the Project 2010-14.2 BAL Standards PRT “believes that the requirements to identify the applicable BA should perhaps be in the interconnection agreements (via FERC’s OATT or NAESB, for example),” we believe these requirements already do.  Many other reliability requirements in the TOP and IRO standards support the identification of Interconnection Facilities through data modeling and specifications.  For example, TOP-003-3 R4 identifies that “each Balancing Authority shall distribute its data specification to entities that have data required by the Balancing Authority’s analysis functions and Real‐time monitoring.”  TOP-003-3 applies to the same entities listed in the draft requirements.

Jason Snodgrass, 9/14/2015

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We appreciate the work by the SDT, but do not agree with moving BAL-005-0.2b Requirement R1 to FAC-001-3 Requirements R5, R6, and R7. At this time, the way the BAL-005 requirement R1 reads it poses to be more of an accounting issue versus a reliability issue. One alternative solution is to remove the language from this standard (FAC-001-3) and include it in the Application Guidelines section.

Mike ONeil, NextEra Energy - Florida Power and Light Co., 1, 9/14/2015

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Payam Farahbakhsh, Hydro One Networks, Inc., 1, 9/14/2015

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The SRC supports deleting the R1 requirements in BAL-005-0.2b, and recommends placing the obligation in a certification requirement.

 

 

See file attached to Question 1 for the full text of the comments to Question 2

ISO Standards Review Committee, Segment(s) 2, 9/14/2015

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Andrea Jessup, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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The FAC-001 standard is used to facilitate interconnection requirements for those entities seeking interconnection into the BES. In the draft FAC-001-3 Requirements R5-R7 the language speaks to those who entities who are already operating in an interconnection and therefore does not fit the purpose of this standard. The FAC-001 standard cannot be used to enforce R5 –R7 for those facilities that already exist.

 

 The LSE function should not be included in the FAC-001 standard and therefore R7 should be removed in its entirety from the draft. In R7, it is not clear if the LSE, TO, or GO will be required to address this in their interconnection requirements. There is no requirement for an LSE to have documented facility interconnection requirements.

 

To truly make this consistent with the purpose of the FAC-001 standard the wording should be revised to address the documented facility interconnection requirements. The draft standard should require that the TO & Applicable GO facility interconnection requirements address BAA metered bounds for those entities seeking interconnection. The entities seeking interconnection should determine their operating area and therefore BAA metered bounds from their desired interconnection location.

 

CSU is of the opinion that these requirements belong in the INT or TOP family of Standards.

Colorado Springs Utilities, Segment(s) 1, 6, 3, 5, 9/14/2015

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Hot Answers

Erika Doot, On Behalf of: Erika Doot, , Segments 1, 5

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The change from BAL-006-2 R3 to BAL-005-1 R1 and R8 seem to be a step in the right direction.  The measures however (BAL-005-1 M1) seems to only require evidence that a common source was agreed upon,  not that the data values were actually exchanged between Adjacent BA’s in a timely manner.  If the intent is only to ensure a common source was identified, then that should be done in certification and does not rise to a Reliability Standard.

 

The need for common megawatt-hour meters between BAs serves only to account for inadvertent interchange between those entities.  Accumulated inadvertent is not related to real-time reliability.  Proposed BAL-005-1 R1 should be removed.

SPP Standards Review Group, Segment(s) , 9/14/2015

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Other Answers

John Fontenot, 8/10/2015

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Andrew Pusztai, 9/4/2015

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Nick Vtyurin, On Behalf of: Manitoba Hydro - MRO - Segments 1, 3, 5, 6

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Thomas Foltz, AEP, 5, 9/8/2015

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Dominion, Segment(s) 5, 6, 1, 3, 9/9/2015

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Richard Vine, 9/9/2015

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Jeremy Voll, Basin Electric Power Cooperative, 3, 9/9/2015

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Jeri Freimuth, 9/9/2015

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Leonard Kula, Independent Electricity System Operator, 2, 9/9/2015

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MWHr meters are for Inadvertent Interchange accounting.  Making this change will confuse the issue and will add unnecessary obligations.  As long as the two BAs use common metering, any minor error in reporting ACE is contained between them and has no impact on the Interconnection as a whole.

MRO-NERC Standards Review Forum (NSRF), Segment(s) 3, 4, 5, 6, 1, 2, 9/9/2015

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MWHr meters are for Inadvertent Interchange accounting.  There are already other requirements proposed that deal with making sure ACE is realatively accurate.  Additionally, as long as adjacent BAs use common metering, any minor error in reporting ACE is contained between them and has no impact on the Interconnection as a whole.

Terry BIlke, 9/10/2015

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MWHr meters are for Inadventent Interchange accounting.  Making the proposed change could lead to confustion and unnecessary obligations.  If the two BAs use common metering, any minor error in ACE reporting is contained and would have no impact on the Interconnection as a whole.

Amy Casuscelli, On Behalf of: Xcel Energy, Inc. - MRO, WECC, SPP RE - Segments 1, 3, 5, 6

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Chris Mattson, 9/10/2015

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Southern Company, Segment(s) 1, 6, 3, 5, 4/13/2015

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Eleanor Ewry, On Behalf of: Puget Sound Energy, Inc., WECC, Segments 1, 3, 5

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We concur with the SDT’s recommendation, as BAL-005-1 addresses more proactive and real-time AGC operations while BAL-006 addresses more after-the-fact.

ACES Standards Collaborators, Segment(s) 1, 3, 5, 6, 4, 9/11/2015

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Jonathan Appelbaum, 9/13/2015

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Texas RE noticed there is no redline for BAL-005-1.  Redlines are helpful in reviewing revisions. 

 

Texas RE noticed BAL-006-2 R3 has the phrase “with readings provided hourly” (emphasis added) which, dictates a timing aspect.  BAL-005-1 R1 has the phrase “to determine hourly megawatt-hour values” but does not have a time aspect specifically required.  Texas RE inquires whether this was the intent of the SDT (and Texas RE is aware of the expected historical practice of hourly communications between entities).

Rachel Coyne, Texas Reliability Entity, Inc., 10, 9/14/2015

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Bob Thomas, 9/14/2015

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John Fontenot, 9/14/2015

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John Fontenot, 9/14/2015

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John Fontenot, 9/14/2015

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Ameren supports MISO's comments for this question

David Jendras, Ameren - Ameren Services, 3, 9/14/2015

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FMPA agrees removing R3 from BAL-006, but it seems to have created duplicative requirements in BAL-005. Requirements R1 and R8 should be combined.

FMPA, Segment(s) , 7/9/2015

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Scott McGough, Georgia System Operations Corporation, 3, 9/14/2015

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The standard states that the purpose is for acquiring data to calculate Reporting ACE. R1 does not fall under that category as it is currently written. It states its purpose is to determine MWh values. PJM suggests the following change to the R1 to align with the purpose of BAL-005:

R1. Each Balancing Authority shall ensure that each Tie‐Line, Pseudo‐Tie, and Dynamic Schedule with an Adjacent Balancing Authority is equipped with a mutually agreed‐ upon time synchronized common source. to determine hourly megawatt‐hour values.

While PJM agrees it is important to maintain a requirement to calculate MWh values for Inadvertent Interchange, PJM suggest this be moved to a NAESB standard.

Mark Holman, 9/14/2015

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For the Quebec Interconnection, it makes more sense for metering issues to be in BAL-006 than BAL-005 since as a single BA asynchronous Interconnection, Net Interchanges are not calculated in our ACE.  However HQ understands that our situation is exceptional and do not oppose the move of BAL-006-2 R3  to BAL-005-1.

Chantal Mazza, On Behalf of: Hydro-Qu?bec TransEnergie - NPCC - Segments 2

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Theresa Rakowsky, 9/14/2015

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Duke Energy agrees with the move to BAL-005-1, however, we recommend that the drafting team revise the Measure for R1 to better align with R1.1. The sub-requirement R1.1 states that megawatt-hour values must be exchanged between Adjacent Balancing Authorities. The Measure provides guidance for R1, but does not provide guidance or example of demonstrating compliance with R1.1. More information is needed to outline how an entity is expected to demonstrate that the exchange of values took place, and how often must the exchange take place.

Duke Energy , Segment(s) 1, 5, 6, 4/10/2014

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Andrea Basinski, 9/14/2015

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LG&E and KU Energy, LLC, Segment(s) 1, 3, 5, 6, 9/11/2015

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Douglas Webb, 9/14/2015

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Matthew Beilfuss, On Behalf of: WEC Energy Group, Inc., MRO, RF, Segments 3, 4, 5, 6

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BAL-006-2--

R3.    Each Balancing Authority shall ensure all of its Balancing Authority Area interconnection points are equipped with                common megawatt-hour meters, with readings provided hourly to the control centers of Adjacent Balancing                       Authorities.

Is there a requirement for hourly reporting?  What is meant by “common”?  Is this a certification issue, or an Interconnection Agreement issue, or a standard?

NPCC--Project 2010-14.2.1 Phase 2 of Bal Auth Rel-based Controls - BAL-005-1, BAL-006-3, FAC-001-3 , Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 9/14/2015

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Jason Snodgrass, 9/14/2015

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Mike ONeil, NextEra Energy - Florida Power and Light Co., 1, 9/14/2015

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Payam Farahbakhsh, Hydro One Networks, Inc., 1, 9/14/2015

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The SRC opposes the proposal to move BAL-006-2 Requirement R3 into BAL-005-3.

The SRC recommends that BAL-006 be deleted.

 

See file attached to Question 1 for the full text of the comments to Question 3

ISO Standards Review Committee, Segment(s) 2, 9/14/2015

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Andrea Jessup, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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N/A

Colorado Springs Utilities, Segment(s) 1, 6, 3, 5, 9/14/2015

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Hot Answers

Erika Doot, On Behalf of: Erika Doot, , Segments 1, 5

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Identification of common sources of measurement (R8) and recording (R1) are BA certification items, not ongoing responsibilities that need to be checked periodically.  New tie lines or “inputs” into the BA ACE calculations should be captured in FAC-001.
 

There is continued confusion regarding the six second scan rate.  A BA can demonstrate a scan rate of its received data every six seconds, but there is no requirement for the data “made available to” the BA to be scanned at a certain scan rate.  To be more clear, the requirement should specify that “measurements should be made by the common source(s) and provided to the BA at least every six seconds for the calculation of Reporting ACE”.  At its worst, that should result in an ACE calculation being made and reported with data no longer than 12 seconds old.

 

The Rational for Requirement R3 leads with a sentence that has no basis in the Functional Model and should be deleted.  The RC does not have responsibility “for coordinating the reliability of bulk electric systems for member BA’s.”  The RC is responsible for “Mitigating energy and transmission emergencies” among other things.  The statement made in the Rationale overstates the responsibility of the RC and minimizes the BA role.  The BA has primary responsibility for maintaining load and generation balance and the RC has authority to step in and provide assistance if the BA is unable to maintain its obligations.  Delete the first sentence of the Rationale for R3 box.  What purpose does it serve to allow a BA an additional 15 minutes after 30 minutes of an inability to calculate ACE before notifying the RC.  Delete “within 45 minutes of the beginning … ACE” and replace with “without delay”.  As stated, the requirement would allow a BA to not calculate Reporting ACE for 44 minutes and then notify the RC.  Or would require a BA that could not calculate Reporting ACE for 31 minutes but then was successful to also notify the RC.  The intent of the change is not clear and seems to indicate a reduction in reliability.

 

What is the specific rationale for requirement of 99.95% (or 0.05% outage allowance = 43 seconds/day) uptime for frequency measurement?  Is some reliability threshold crossed at 44 seconds of frequency measurement unavailability each day? Is the intent of R4.2 to still require calibration of the measurement or simply to utilize a provided significant digit of .001 Hz?  The new R4 uses the term “accuracy” of .001Hz rather than the old R17 description of “<=0.001Hz”.  Also the measurement M4 requires demonstration of “minimum accuracy” which lends itself to requiring a demonstrable calibration that is not specifically stated in R4.  The intended statement in the mapping document for R17 to R4 is not captured well in the resulting R4.

 

Suggest deleting R5 and suggest this requirement be evaluated for inclusion in the Project 2009-02 Real-Time Monitoring and Analysis Capabilities work since it relates to identifying sources of inccorect input data.  Any Operating Process or Procedure to identify, correct, or mitigate incorrect or lost input data out of Project 2009-02 should include ACE data.  If kept, the Measure M5 includes an additional requirement that the suspect/garbage data indication should be indicated on BOTH the calculated Reporting ACE result as well as on the individual suspect/garbage data point.  We suggest that R5 should include similar language to M5 if that is the intent.  The RSAW should be adjusted based on changes to R5 or M5.

Suggest deleting R6 as it is duplicative and in conflict with BAL-001-2.  The reliability implication of “knowing” ACE is to be able to ensure balance is maintained.  That is accomplished in CPS and BAAL and does not need to be duplicated here.  The reporting % does not indicate a direct measurement of reliability and is administrative only.

 

Suggest deleting R7 and suggest this requirement be evaluated for inclusion in the Project 2009-02 Real-Time Monitoring and Analysis Capabilities work since it relates to identifying sources of inccorect input data.  Any Operating Process or Procedure to identify, correct, or mitigate incorrect or lost input data out of Project 2009-02 should include ACE data. 

 

Regarding R8:  There is no demonstration of the reliability impact of using non-common meters between BA’s for the purpose of Reporting ACE.  In fact, in order to support reliability, the requirement should specify that redundant sources be made available  to be used for Reporting ACE.  Loss of the single, common source would result in lost input to the ACE calculation.  A best practice that most BA’s use is to identify a primary, common source for measurements and a secondary, common source for measurements and ensure each adjacent BA is using the same common source at the same time.  Common source measurements do not ensure accuracy, they just ensure the same error is introduced in both adjacent ACE calculations and therefore net each other out.

 

SPP Standards Review Group, Segment(s) , 9/14/2015

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Other Answers

none

John Fontenot, 8/10/2015

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Andrew Pusztai, 9/4/2015

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Nick Vtyurin, On Behalf of: Manitoba Hydro - MRO - Segments 1, 3, 5, 6

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Thomas Foltz, AEP, 5, 9/8/2015

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Dominion, Segment(s) 5, 6, 1, 3, 9/9/2015

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Richard Vine, 9/9/2015

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Jeremy Voll, Basin Electric Power Cooperative, 3, 9/9/2015

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Jeri Freimuth, 9/9/2015

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a.         Notwithstanding our comments on selected requirements provided below, as an overall comment we do not believe some of the proposed requirements belong to a Reliability Standard. We believe Requirements  R2, R4, R5 and R6 are more suited for inclusion in the Organization Certification Requirement for Balancing Authorities since these requirements stipulate the capabilities and facilities that need to be in place to enable a BA to perform its tasks. These are "one-off" requirements that do not drive continuous behaviors, and they do not require frequent updates.  

b.         Requirement R4: The 99.95% uptime is overly prescriptive and there does not exist any technical justification. Unless supported by technical justification, this requirement should be removed. Further addition, the 0.001 Hz “accuracy” requirement is misleading. We suggest to replace "accuracy" with "resolution" to more properly convey the requirement. 

c.        Requirement R5: We agree with the need to provide operating personnel with accurate information that supports awareness and calculation of Reportable ACE, but the examples listed places emphasis on the secondary information as it fails to capture the more important pieces of information which were listed in the existing BAL-005. We therefore suggest R5 be revised to:

R5. The Balancing Authority shall make available to the operator information associated

with Reporting ACE including, but not limited to, real-time values for ACE, Interconnection

frequency, Net Actual Interchange with each Adjacent Balancing Authority Area and quality flags indicating missing or invalid data.

d.      R6: As with our comments on R4, the 99.5% uptime is overly prescriptive and restrictive, and there does not exist any technical justification. A 99.5% uptime requirement means that all model builds and software glitches couldn’t exceed 43.8 hours in any given year. This is overly restrictive. Unless supported by technical justification, this requirement should be removed.

e.        R7: This requirement is not needed. R1 already stipulates the need to calculate and hourly megawatt‐hour values (and Reporting ACE, as we suggested above); and R4 already stipulates the scan rate. Failure to meet either requirement will result in a BA being unable to comply with the standard in which case the BA must develop corrective actions to return to compliance. Having an explicit operating process to identify and mitigate errors affecting the scan‐rate accuracy of data used in the calculation of Reporting ACE is redundant to the combined requirements in R1 and R4. We therefore suggest to remove R7.

If for whatever reasons R7 is retained, then the term “Operating Process” should not be capitalized since it is not a NERC defined term.

f.         R8: This requirement is implied in and redundant with, R1. Suggest to remove it.

Leonard Kula, Independent Electricity System Operator, 2, 9/9/2015

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See attachment with Strikethrough

The proposed R1 should be shortened and merged with R7.  There need not be mention of “mutually agreed upon” nor “time sychnronized”.  AGC and ACE use real-time values, not hourly values.

BAL-005-1

R1.    Each Balancing Authority shall ensure that have a process to operate to common, accurate each Tie‐Lines, Pseudo‐Ties, and Dynamic Schedules with its an Adjacent Balancing Authorities. is equipped with a mutually agreed upon time synchronized common source to determine hourly megawatt‐hour values

The measure of this requirement is not logs or voice recordings.  NSI is already checked with Inadvertent Accounting and the INT standards.  The process that was proposed in R7 could be the validation and measure for R1

If the change to R1 above is made, R7 is no longer necessary.

R8 is redundant with when compared to the suggested wording above for BAL-005-1 R1 and BAL-006 R3. 

MRO-NERC Standards Review Forum (NSRF), Segment(s) 3, 4, 5, 6, 1, 2, 9/9/2015

Project 2010-14..4.pdf

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The proposed R1 should be shortened and merged with R7.  There need not be mention of “mutually agreed upon” nor “time sychnronized”.  AGC and ACE use real-time values, not hourly values.

BAL-005-1

R1.    Each Balancing Authority shall have a process to operate to common, accurate Tie‐Lines, Pseudo‐Ties, and Dynamic Schedules with its Adjacent Balancing Authorities.

The measure of this requirement should not be logs or voice recordings.  NSI is already checked with Inadvertent Accounting and the INT standards.  The process that was proposed in R7 could be the validation and measure for R1

If the change to R1 above is made, R7 is no longer necessary.

R8 is redundant with when compared to the suggested wording above for BAL-005-1 R1 and BAL-006 R3

Terry BIlke, 9/10/2015

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The proposed R1 should be shortened and merged with R7.  No mention of “mutually agreed upon” nor “time sychnronized” is necessary.  AGC and ACE use real-time values, not hourly values.

We suggest the following:

BAL-005-1
R1.    Each Balancing Authority shall have a process to operate to common, accurate Tie‐Lines, Pseudo‐Ties, and Dynamic Schedules with its Adjacent Balancing Authorities.

The measure of this requirement is not logs or voice recordings.  NSI is already checked with Inadvertent Accounting and the INT standards.  The process that was proposed in R7 could be the validation and measure for R1.

R7 would not be necessary if the change to R1 above is made and R8 would be redundant with when compared to the suggested wording above for BAL-005-1 R1 and BAL-006 R3.

Amy Casuscelli, On Behalf of: Xcel Energy, Inc. - MRO, WECC, SPP RE - Segments 1, 3, 5, 6

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Chris Mattson, 9/10/2015

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Southern Company, Segment(s) 1, 6, 3, 5, 4/13/2015

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No comments.

Eleanor Ewry, On Behalf of: Puget Sound Energy, Inc., WECC, Segments 1, 3, 5

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  1. We believe Requirement R1 should focus on detection and correction of a problem rather than a guarantee that a common source is available.  This would better align with a risk-based approach that NERC is mandating during standard development.  We believe this can be achieved by rephrasing the requirement to read “Each Balancing Authority shall monitor mutually agreed-upon time-synchronized common source with Adjacent Balancing Authorities to determine hourly megawatt‐hour values for each common Tie‐Line, Pseudo‐Tie, and Dynamic Schedule.”  We feel that by moving in this direction, the associated VSLs can be set to more adjustable criteria, such as the length of time between detection and correction, (e.g. under 30, 60, and 90 days).
  2. We feel the SDT should align the VSLs for R2 to more performance-based criteria.  We agree that six-seconds is a reasonable benchmark, but question if it needs to be categorized as a severe VSL.  Instead, we recommend assigning a sliding time scale to each VSL (e.g. greater than or equal to 6 seconds, and greater than or equal to 12 seconds, etc.)
  3. In Requirement R3, the BA is expected to notify its RC within 45 minutes from the beginning of its inability to calculate Reporting ACE.  If a BA encounters multiple instances when it is unable to calculate its Reporting ACE in a consecutive minute time period, but never haves an instance that is greater than thirty consecutive minutes, we want to confirm that the time period for notification begins with the first reportable instance.  We believe this can be accomplished by replacing “an inability” with “the inability” at end of the requirement to read “…within 45 minutes of the beginning of the inability to calculate Reporting ACE.”
  4. We believe System Operators should be identified in Requirement R5, as this is a NERC-defined Glossary Term.  Moreover, it does not provide any ambiguity for auditors and better aligns with those personnel identified to complete training for reliability-related tasks in Reliability Standard PER-005-2.
  5. For Requirement R5, we agree with the SDT’s approach that Reporting ACE can be a primary metric to determine operating actions or instructions.  Furthermore, System Operators should be aware of when such metrics are based on poor or insufficient data.  However, we disagree with the SDT’s approach taken in the wording of this requirement.  Proof of the existence of a graphical display or dated alarm log, as mentioned as possible evidence for compliance, will only lead to confusion on how evidence should be presented.  We believe rewording this requirement to “each Balancing Authority shall monitor the quality of information used to calculate its own Reporting ACE” achieves the intent of “making available” sufficient data to System Operators.
  6. We feel the SDT should provide rationale on the need for Requirement R6.  While we agree that “Reporting ACE is an essential measurement of the BA’s contribution to the reliability of the Interconnection,” we believe a requirement measuring the availability of a Reporting ACE calculation system is unnecessary.  System Operators, when in distress, likely will rely on frequency meter measurements and communications with other Adjacent BAs when Reporting ACE is not available.  This proposed standard already has an availability requirement listed in Requirement R4, and with a requirement that has a higher availability rate.  We believe requiring a system be available should be reserved for the ERO Event Analysis Process, much like SCADA is for RCs and TOPs.
  7. We believe the VSLs criteria for Requirement R7 could be more performance-based, particularly with how fast the BA took to mitigate errors affecting the scan‐rate accuracy of data.  We recommend sliding scale criteria, such as within 15 minutes, within 30 minutes, etc.
  8. In Requirement R8, we believe the requirement should focus on detection and correction to better align with a risk-based approach.  We believe this can be achieved by rephrasing the requirement to read “Each Balancing Authority shall use a common source for Tie‐Lines, Pseudo-Ties, and Dynamic Schedules with Adjacent Balancing Authorities when calculating Reporting ACE.”  We feel that by moving the requirement in this direction, the associated VSLs can be set to adjustable criteria, such as the length of time between detection and correction, i.e. under 15 minutes, under 30 minutes, etc.
  9. The data retention of the proposed standard, current year plus three years, is significantly larger than the one year retention found in the current standard and goes beyond the three-year audit cycle for BAs.  In the context of a Risk-Based CMEP, we feel an entity should only need to retain one year’s worth of data.  There is minimal reliability benefit to requiring an entity to store data for longer than one year, especially considering the tools in place for the ERO to spot check or self-certify compliance activities more frequently than an audit.
  10. We believe the Implementation Plan should be updated to account for the retirement of IRO-005-3.1a, as Requirement R1.6 of that standard has the RC monitoring ACE and not Reportable ACE for all its BAs.
  11. The third bullet of the proposed definition for Automatic Time Error Correction, as listed within the Implementation Plan, has a typographical error and should reference ε10.

ACES Standards Collaborators, Segment(s) 1, 3, 5, 6, 4, 9/11/2015

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Jonathan Appelbaum, 9/13/2015

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As stated in the answer to Question 1, Texas RE is concerned the SDT has not considered interconnections with a single BA.  The initial SAR comments included the following statement: “Within the Purpose statement or Applicability section, the PRT also recommends that the SDT consider addressing the Hydro Quebec exception for tie line bias control in some form, or a single-BA exception.“  It does not appear the SDT addressed the single-BA issue which results in the Reliability Standard not being applicable to the ERCOT and Quebec Interconnections.  This, in turn, affects BAL-001 applicability. If Reporting ACE is not applicable to interconnections with a single BA, BAL-001 might not apply to the ERCOT and Quebec Interconnections. Additionally, any BA that connects with the ERCOT Interconnection BA will not be able to accurately determine Reporting ACE which could cause failure of BAL-001 for those BAs (assuming they utilize net interchange values in their Reporting ACE).  This omission creates a reliability gap. Texas RE recommends including Interconnections with a single BA.

There seems to be some inconsistency with regards to definitions.  For example, the definition of “Reporting ACE” in the Standard is different than the NERC Glossary of Terms (Glossary) but there is no redline.  The definition of “AGC” is different from the Glossary and there is a redline.  Is intent of the SDT to change both terms in the Glossary?  Frequency Bias Setting is not defined within this Standard so it appears there is no change to that term.  Asynchronous Ties should be included in the derivation of ACE where applicable.   Without it, Reporting ACE will be off by the magnitude frequency applicable to the flows across a DC tie (especially if a trip of the DC occurs or an error in scheduling).   

 

Texas RE noticed the term  “adjacent” is not capitalized in M1.  Texas RE recommends removing  “its” when describing “Adjacent Balancing Authority” as there could be more than one Adjacent Balancing Authority in M1. 

 

To make R5 consistent with the Purpose statement, Texas RE recommends changing “operator” to System Operator to be clear on which “operator” the information shall be made available.  This change should also take place in the VSL for R5.

 

Per the comment in Question 1, R7 should be for all BAs not just BAs “within a multiple Balancing Authority Interconnection”.  R7 should only be relevant to the area of the Balancing Authority that is implementing an Operating Process.

 

Texas RE noticed the VSL for R1 does not include language should include language for each Tie Line, Pseudo-Tie or Dynamic Schedule to be equipped with an agreed upon source to determine values.  As is, the VSL ignores the “equipped” language within the Standard.

 

Texas RE noticed the VSL language for R3 does not include “for 30 consecutive minutes”.  Should there be a dash in “30-consecutive” in Requirement 3?

 

Texas RE recommends changing the verbiage from “each calendar year” to “annually” or for “each rolling 12 month period”.  Specifically, R4 and R6 include the term “calendar year” which  implies Jan 1 to Dec 31.  Therefore, if a CEA evaluates compliance to the Requirement in mid-year, there cannot be an assertion of compliance for the current year.  Consequently, if the CEA returns in two years, the half year’s period of data should be available to ascertain compliance (per the Evidence Retention statements.  Texas RE would like the SDT consider whether this violates the RoP  Appendix 4C Section 3.1.4.2 Period Covered “The audit period will not begin prior to the End Date of the previous Compliance Audit.”?  Morever, does it cause a gap in compliance monitoring (and reflect a possible gap in reliability)?

Rachel Coyne, Texas Reliability Entity, Inc., 10, 9/14/2015

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Bob Thomas, 9/14/2015

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John Fontenot, 9/14/2015

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John Fontenot, 9/14/2015

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John Fontenot, 9/14/2015

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Ameren supports MISO's comments for this question

David Jendras, Ameren - Ameren Services, 3, 9/14/2015

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FMPA disagrees with the use of the term “accuracy” in R4.2. We believe the intent would be better described by the term “precision”, or perhaps “degree of accuracy”.

FMPA does not find any technical justification for the 99.5% availability requirement in R6, and believes it may be duplicative with BAL-001 and present a double jeopardy issue.
 

FMPA, Segment(s) , 7/9/2015

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Scott McGough, Georgia System Operations Corporation, 3, 9/14/2015

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Proposed Standard:
Located in BAL-005-1 R1:
R1. Each Balancing Authority shall ensure that each Tie‐Line, Pseudo‐Tie, and Dynamic Schedule with an Adjacent Balancing Authority is equipped with a mutually agreed‐ upon time synchronized common source to determine hourly megawatt‐hour values.
1.1. These values shall be exchanged between Adjacent Balancing Authorities.

The phrase “Tie-Line” is not listed in the NERC Glossary, but instead “Tie Line” is listed.
Definition:
o    Tie Line:
•    A circuit connecting two Balancing Authority Areas.

The definition of “Pseudo-Tie” should be updated to include Reporting ACE if that is the purpose of the BAL-005-1 R1.
Definition:
o    Pseudo-Tie:
•    A time-varying energy transfer that is updated in Real-time and included in the Actual Net Interchange term (NIA) in the same manner as a Tie Line in the affected Balancing Authorities’ control ACE equations (or alternate control processes).

If the SDT chooses not to change the language for R1, the language in R1.1 should be modified. With the current langauge the purpose of R1.1 is to exchange the hourly megawatt‐hour values with the appropriate Balancing Authority to determine billing and Inadvertent Interchange. This should be stated more clearly as the current requirement has it written that the values are shared with [any] Adjacent Balancing Authority.

PJM proposes the following R1.1:
1.1. These values shall be exchanged for each Tie Line, Pseudo‐Tie, and Dynamic Schedule shared between affected Balancing Authorities.

Mark Holman, 9/14/2015

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  • In the Mapping Document for BAL-005-1, R9,  there appears to be a contradiction in the Description and Change Justification section about the HVDC links  and their inclusion or not in Reporting ACE calculation vs the definitions of Scheduled and Actual Net Interchanges that exclude asynchronous DC tie-lines directly connected to another interconnection.
  • R1 vs R8:   HQ faila to see the difference between the 2 requirements.  Perhaps the Rationales should be enhanced for a better understanding.
  • M1 and M8 do not seem  appropriate measures  for an agreement on common metering or other sources. HQ suggesst favoring a written agreement rather than operator logs or voice recordings.
  • Even though HQ agrees that balancing authorities should use common metering equipment, we feel that R1 does not belong in BAL-005.  This requirement relates to energy measurements that are used for accounting purposes and that do not come into play in reporting ACE calculation.  This requirement should remain in BAL-006 and does not affect in any way  automatic generation control.  R8 does address perfectly the common metering needs between balancing authorities for real-time control.

Chantal Mazza, On Behalf of: Hydro-Qu?bec TransEnergie - NPCC - Segments 2

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For BAL-005, R8, “MW Flow Values” should be specifically mentioned in R8 and not just in the R8 Rationale.

Theresa Rakowsky, 9/14/2015

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General comment: Duke Energy recommends the drafting team consider moving the proposed R8 to R2. We feel that based on the common subject matter of both of these requirements, that it would be more appropriate to have them consecutively listed within a standard.

R4: Duke Energy requests further clarification regarding on how an entity may demonstrate compliance with R4.2 specifically. Also, more background information regarding where the 0.001Hz number came from and what it is measure against would add to clarity of the standard. Perhaps an Operating Guideline that provides guidance or examples on how an entity may demonstrate compliance, as well as a background on the 0.001Hz number.

R5: We request further clarification on the use of the term operator in R5. Is this in reference to a System Operator, if so, we recommend stating so in the standard. As written, it appears that the standard is in conflict with the rationale for R5 which uses the term System operator.

Duke Energy , Segment(s) 1, 5, 6, 4/10/2014

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As worded, we do not believe  that BAL-005-0.2b Requirement R1 is appropriate for FAC-001-3.  Since FAC-001-3 applies to documented Facility interconnection requirements, it would be more appropriate to require that the documented interconnection requirements contain language stating that transmission, generation and end-user interconnected Facilities must be located within the Balancing Authority Area’s metered boundaries.  This could be accomplished by adding R3.3 stating “Procedures for ensuring that transmission Facilities, generation Facilities and end-user Facilities are within the Balancing Authority Area’s metered boundaries.”  The requirement to verify that existing facilities are located with the metered boundaries of a Balancing Authority Area is most appropriately assigned to the TOP, and not to the TO, GO and the LSE.

Andrea Basinski, 9/14/2015

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LG&E and KU Energy, LLC, Segment(s) 1, 3, 5, 6, 9/11/2015

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KCP&L incorporates by reference its response to Survey Question No. 2.

Douglas Webb, 9/14/2015

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Matthew Beilfuss, On Behalf of: WEC Energy Group, Inc., MRO, RF, Segments 3, 4, 5, 6

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In the Automatic Generation Control (AGC) definition consider removing “Automatically adjusts” and replace it with “determines”.  The BA does not always have the capability of making an automatic adjustment.  For example, a BA can send a requested loading value down through the RIG (Remote Intelligent Gateway) and have the local GO/GOP or DP/LSE with smaller units to meet the load, but do not have direct control over the units. It’s the local GO/GOP or DP/LSE who owns and/or operates the units that actually execute changes in loading.

 

Requirement R1

The use of the following text needs to be reconsidered:

… each Tie‐Line, Pseudo‐Tie, and Dynamic Schedule with an Adjacent BA…

… time-synchronized common source…

… to determine hourly megawatt‐hour values

Pseudo-ties and Dynamic Schedules are not tie lines; they are output values from resources. In some cases these output values can be used directly, but in other cases the values are adjusted by the EMS to represent the proportion of the output to be incorporated into the BAs ACE.

The phrase “time-synchronized common source” requires explanation. If two BAs are using a common source for real time flows, then by definition the values are synchronized. If, on the other hand, R1 only applies to Hourly (Billing) values the phrase is still superfluous. However, if the phrase is meant to mandate that all inter-tie meters be synchronized to a common time, then that needs to be explained more clearly.

Agree that Real-time metering of interties requires the use of common sources to both BAs (as per Requirement 8). But given that R1 is focused on hourly megawatt-hour values, the requirement becomes a market/billing issue not a Real-time issue.  R1 should be revised to clarify the intent. 

            Suggest that the Real-time installation of meters be left to BA Certification.

 

 

Requirement R2

What is meant by a 6 second sampling rate? Is that that the rate that a BA samples the data values it has at the moment, or does the 6 seconds represent a time delay between real-time and ACE calculations? This can be an issue for BAs that make use of multi-tier samples, where Owner X samples a group of resources every X-seconds, then sends that block of data to the BA who would sample all the blocks every Y-seconds.

Traditionally, sampling rates were associated with how well a continuous function can be recreated. A sampling rate that is slower that the fundamental oscillations in the continuous function will not be able to reproduce that original function (the issue of aliasing as experienced in watching a TV program in which a wheel appears to rotate in the wrong direction).

What is the reliability justification for this scan rate?

 

Requirement R4

The value of monitoring system frequency is recognized, but again as suggested in our response to R1, the issue of frequency monitoring would seem to be better suited to a certification process rather than to a mandatory standard. 

What is the justification for the values in Parts 4.1 and 4.2?

 

Requirement R5

 The value of alarming is recognized, but given the fact that R5 could be a federal law, the question could be asked:

  • What constitutes “quality” as in quality flags?
  • What constitutes “invalid” as in invalid data?

The concern addressed in R5 (alarming) would be better addressed in certification. The systems that are certified should have alarming processes built into them, customized to the needs of the BA.

 

Requirement R6

Real-time errors in the ACE components are reflected in various other parameters:

1.     System Frequency

2.     Time Error (even if TE is not a standard is still computed)

3.     End of Day checkouts

4.     End of Month billing

As written R6 is an exercise is data collection and manipulation.

What are the implications of an unavailability less than 99.5%, and at what points are reliability impacted (and how)?

 

            Requirement R7

Requirement R7 requires clarification. 

The process of monitoring for data errors and the process for mitigating errors that are identified are built into modern EMS systems. 

The requirement as written focuses only on errors “affecting the scan‐rate accuracy of data used in the calculation of Reporting ACE…”. As written, this is not all data used in ACE. Moreover, data does not impact the accuracy of the rate of scanning. The rate of scanning is a built in function to the EMS / SCADA programs. The data (good or bad) is scanned regularly.

As written R7 does not rise to the level of a NERC standard and should be deleted.

The intent of R1 should be to ensure that a common metering point be identified for all Real-time inter-BA tie lines. The issue of Pseudo-Ties and Dynamic Schedules is really a business agreement between the two BAs in cooperation with the resource being used, and therefore is not a standard matter.

 

 Requirement R8

The requirement is on Pseudo-ties and Dynamic Schedules, but Pseudo-Ties and Dynamic Schedules are not tie lines, they are output values from resources. In some cases these output values can be used directly, but in other cases the values are adjusted by the EMS to represent the proportion of the output to be incorporated into the BA’s ACE.

The requirement to utilize a common source for all interties is a valid requirement.

The agreements referred to in R8 are Interconnection Agreements and therefore not a matter for a NERC standard.

NPCC--Project 2010-14.2.1 Phase 2 of Bal Auth Rel-based Controls - BAL-005-1, BAL-006-3, FAC-001-3 , Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 9/14/2015

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Jason Snodgrass, 9/14/2015

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Mike ONeil, NextEra Energy - Florida Power and Light Co., 1, 9/14/2015

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Payam Farahbakhsh, Hydro One Networks, Inc., 1, 9/14/2015

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See file attached to Question 1 for the SRC comments on the rationale and language of several requirements.

ISO Standards Review Committee, Segment(s) 2, 9/14/2015

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In general, BPA agrees with the current draft of BAL-005-1 but has some concerns with how BAs will meet the proposed R7 – relating to implementing an “Operating Process”.  BPA believes that R7 is poorly written and needs to be revisited.

Andrea Jessup, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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N/A

Colorado Springs Utilities, Segment(s) 1, 6, 3, 5, 9/14/2015

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Hot Answers

Erika Doot, On Behalf of: Erika Doot, , Segments 1, 5

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The purpose of BAL-006-2 (and resulting BAL-006-3) do not impact reliability.  In fact, this enforceable Standard only serves to provide administrative metrics that are then used to facilitate either financial or in-kind reimbursements.  In order to make this standard truly results based in relation to system reliability, requirements such as a BA shall not accumulate inadvertent interchange in excess of XX,XXX MWh per month would need to be created.  No BA or RC will ever take reliability actions or issue Operating Instructions in relation to the accumulated or forecast accumulated inadvertent interchange.  Resolution of inadvertent is an after-the fact reimbursement and not a reliability issue.

SPP Standards Review Group, Segment(s) , 9/14/2015

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Other Answers

none

John Fontenot, 8/10/2015

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Andrew Pusztai, 9/4/2015

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Nick Vtyurin, On Behalf of: Manitoba Hydro - MRO - Segments 1, 3, 5, 6

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Thomas Foltz, AEP, 5, 9/8/2015

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Dominion, Segment(s) 5, 6, 1, 3, 9/9/2015

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Richard Vine, 9/9/2015

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Jeremy Voll, Basin Electric Power Cooperative, 3, 9/9/2015

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Jeri Freimuth, 9/9/2015

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We do not see the need to retain any of the BAL-006 requirements in a NERC Reliability Standard. Standard. Inadvertent Interchange is calculated for reconciliation purpose and as such, does not have any reliability value for real-time operations or post-mortem analysis. The facilities used for recording hourly Inadvertent Interchange are more suited to be stipulated in the BA’s Organization Certification Requirements; the procedure to calculate, reconcile and resolve disputes over Intervertent Interchange can be put into operating guide or even in the NAESB’s business practices.

Consistent with the risk-based principle, we suggest that unless there is clear demonstration that failure to calculate and reconcile Inadvertent Interchange can adversely affect operating reliability, this standard should be retired with its requirements transferred to other NERC and/or NAESB documents.

Leonard Kula, Independent Electricity System Operator, 2, 9/9/2015

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R1 is embedded in R2 and R3 and therefore unnecessary.

The sub-bullets of R3 should be bullets and not Requirements.  Additionally, the end-of-day check should be an agreement of on and off peak totals, not hourly values.  There are INT standards that require confirmation of hourly schedules. 

In the compliance section, RROs do not fill out monthly summary reports and submit them to NERC.

MRO-NERC Standards Review Forum (NSRF), Segment(s) 3, 4, 5, 6, 1, 2, 9/9/2015

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Terry BIlke, 9/10/2015

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The sub-requirements of R3 should be bullets, not sub requirements.

The end of day check should be an agreement of on and off peak totals, not hourly values.  Confirmation of hourly schedules are already required in other standards.

Amy Casuscelli, On Behalf of: Xcel Energy, Inc. - MRO, WECC, SPP RE - Segments 1, 3, 5, 6

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Chris Mattson, 9/10/2015

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Southern Company, Segment(s) 1, 6, 3, 5, 4/13/2015

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No comments.

Eleanor Ewry, On Behalf of: Puget Sound Energy, Inc., WECC, Segments 1, 3, 5

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We appreciate the SDT’s efforts to remove Requirement R3 from this standard.

ACES Standards Collaborators, Segment(s) 1, 3, 5, 6, 4, 9/11/2015

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Jonathan Appelbaum, 9/13/2015

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In the revised language for BAL-006-3 R4, Texas RE recommends replacing the  undefined term “Regional Reliability Organization Survey Contact” with Reliability Coordinator.  This may be outside the purview of the SDT but consideration should be provided to clarify the responsibility while the Standard is being considered.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 9/14/2015

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Bob Thomas, 9/14/2015

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John Fontenot, 9/14/2015

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John Fontenot, 9/14/2015

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John Fontenot, 9/14/2015

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Ameren supports MISO's comments for this question

David Jendras, Ameren - Ameren Services, 3, 9/14/2015

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n/a

FMPA, Segment(s) , 7/9/2015

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Scott McGough, Georgia System Operations Corporation, 3, 9/14/2015

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Mark Holman, 9/14/2015

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Chantal Mazza, On Behalf of: Hydro-Qu?bec TransEnergie - NPCC - Segments 2

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As stated in question #2 above, as worded, we do not believe these requirements are appropriate for FAC-001-3.  Since FAC-001-3 applies to documented Facility interconnection requirements, it would be more appropriate to require that the documented interconnection requirements contain language stating that transmission, generation and end-user interconnected Facilities must be located within the Balancing Authority Area’s metered boundaries.  This could be accomplished by adding R3.3 stating “Procedures for ensuring that transmission Facilities, generation Facilities and end-user Facilities are within the Balancing Authority Area’s metered boundaries.”  The requirement to verify that existing facilities are located with the metered boundaries of a Balancing Authority Area is most appropriately assigned to the TOP, and not to the TO, GO and the LSE.

Theresa Rakowsky, 9/14/2015

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Duke Energy , Segment(s) 1, 5, 6, 4/10/2014

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Andrea Basinski, 9/14/2015

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LG&E and KU Energy, LLC, Segment(s) 1, 3, 5, 6, 9/11/2015

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KCP&L incorporates by reference its response to Survey Question No. 2.

Douglas Webb, 9/14/2015

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Matthew Beilfuss, On Behalf of: WEC Energy Group, Inc., MRO, RF, Segments 3, 4, 5, 6

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NPCC--Project 2010-14.2.1 Phase 2 of Bal Auth Rel-based Controls - BAL-005-1, BAL-006-3, FAC-001-3 , Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 9/14/2015

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Jason Snodgrass, 9/14/2015

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Mike ONeil, NextEra Energy - Florida Power and Light Co., 1, 9/14/2015

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Payam Farahbakhsh, Hydro One Networks, Inc., 1, 9/14/2015

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The SRC recommends that BAL-006 be retired.

 

See file attached to Question 1 for the full text of the comments to Question 5

ISO Standards Review Committee, Segment(s) 2, 9/14/2015

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None.

Andrea Jessup, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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N/A

Colorado Springs Utilities, Segment(s) 1, 6, 3, 5, 9/14/2015

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Hot Answers

Reclamation agrees with the periodic review team that it is important to verify facilities are within the metered boundaries of a Balancing Authority Area before they are operational, but believes that the requirement should be imposed through interconnection or service agreements rather than a reliability standard.  As an alternative, FAC-001-3 R5 through R7 and M5 through M7 could be rephrased to require a one-time confirmation prior to a facility being placed in service.

Erika Doot, On Behalf of: Erika Doot, , Segments 1, 5

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The first 4 requirements, which make up the existing FAC-001-2, are administrative and should be moved to certification review.  The new R5-7 are necessary due to the removal from BAL-005.  However as suggested earlier, those requiremetns should also be included in the TO’s Facility Interconnection Requirement documents and do not necessarily need to be specific Reliability Standard Requirements.  If R1-4 are kept, we recommend changing the phrase “shall address” in R1-4 to “shall include”.

SPP Standards Review Group, Segment(s) , 9/14/2015

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Other Answers

none

John Fontenot, 8/10/2015

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Andrew Pusztai, 9/4/2015

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In the  “Table of Compliance Elements”,  the Violation  Severity Levels, R5 and R6  should correctly refer  to Transmission Owner and  Generator Owner, respectively (instead of Transmission Operator and  Generator Operator)

Nick Vtyurin, On Behalf of: Manitoba Hydro - MRO - Segments 1, 3, 5, 6

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Thomas Foltz, AEP, 5, 9/8/2015

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Richard Vine, 9/9/2015

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Jeremy Voll, Basin Electric Power Cooperative, 3, 9/9/2015

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APS agrees with moving these requirements from BAL-005 to the new FAC-001-3.  APS also agrees with the proposed requirement language.  APS does not agree that the measurements of these newly placed requirements have been correctly drafted. 

A Transmission Operator, Generator Operator, or Load-Serving-Entity possessing the Facility interconnection requirements of the Transmission Owner they are attempting to interconnect with is not proof they are within a Balancing Authority Area.  Evidence they are within a Balancing Authority Area would be demonstrated by possessing an executed Interconnection Agreement or similar contract.  The measures will need to be corrected to reflect that.  The RSAW will need to be corrected to line up with those changes.

Jeri Freimuth, 9/9/2015

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We concur with the proposed revisions to FAC-001-3.

Leonard Kula, Independent Electricity System Operator, 2, 9/9/2015

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MRO-NERC Standards Review Forum (NSRF), Segment(s) 3, 4, 5, 6, 1, 2, 9/9/2015

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Do not change FAC-001 as this confuses the intent of the original requirement.  There is virtually no way to prove that a particular component is within a BA.  The original requirement was intended to be sure Control Areas balanced.  This is done by operating to common ties and performing Inadvertent Interchange checkouts.

Terry BIlke, 9/10/2015

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Amy Casuscelli, On Behalf of: Xcel Energy, Inc. - MRO, WECC, SPP RE - Segments 1, 3, 5, 6

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1)      FAC-001-3 R5 Severe VSL should state “The Transmission Owner……” to match R5 which places responsibility for the requirement on the Transmission Owner. Currently the VSL states the Transmission Operator will comply.

2)      FAC-001-3 R6 Severe VSL should state “The Generator Owner……” to match R6 which places responsibility for the requirement on the Generator Owner. Currently the VSL states the Generation Operator will comply.

Chris Mattson, 9/10/2015

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Should the SDT disagree that existing processes are adequate to accomplish the desired outcome (as described in the comments to Question #2), then the following is recommended:

  1. Remove the inseration of 4.1.3 and R5-R7.
  2. Modify R3.2 to read “Procedures for notifying the BA, TOP and RC of new or materially modified existing interconnections.”
  3. Modify R4.2 to read “Procedures for notifying the BA, TOP and RC of new interconnections.”

Additionally, if possible, it is recommended that there be continued coordination with the FAC-001 team that produced FAC-001-2 in 2014 before any changes to FAC-001-2 are made.

Southern Company, Segment(s) 1, 6, 3, 5, 4/13/2015

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As stated in question #2 above, as worded, we do not believe these requirements are appropriate for FAC-001-3.  Since FAC-001-3 applies to documented Facility interconnection requirements, it would be more appropriate to require that the documented interconnection requirements contain language stating that transmission, generation and end-user interconnected Facilities must be located within the Balancing Authority Area’s metered boundaries.  This could be accomplished by adding R3.3 stating “Procedures for ensuring that transmission Facilities, generation Facilities and end-user Facilities are within the Balancing Authority Area’s metered boundaries.”  The requirement to verify that existing facilities are located with the metered boundaries of a Balancing Authority Area is most appropriately assigned to the TOP, and not to the TO, GO and the LSE.

Eleanor Ewry, On Behalf of: Puget Sound Energy, Inc., WECC, Segments 1, 3, 5

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We believe FAC-001-3 should not be modified based on the reasons previously provided in question #2.  We recommend the SDT retire the requirements moved from BAL-005-0.2b based on the reasons cited.  At a minimum, we recommend the SDT provide technical justification on why these requirements are necessary.

ACES Standards Collaborators, Segment(s) 1, 3, 5, 6, 4, 9/11/2015

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Jonathan Appelbaum, 9/13/2015

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In R5, R6, and R7 it seems duplicitous to include, “metered boundaries” in the phrase “Balancing Authority Area’s metered boundaries” because the first sentence of Balancing Authority Area definition is “The collection of generation, transmission, and loads within the metered boundaries of the Balancing Authority.”

Texas RE noticed the Evidence Retention section does not address LSEs.

Texas RE noticed the format of FAC-001-3 does not follow the new NERC Results Based Standards Template.                                                                                                   

Texas RE noticed the VSL for R5 refers to the “Transmission Operator” but the Requirement is applicable to the Transmission Owner.  The VSL for R6 refers to the “Generator Operator” but the Requirement is applicable to the Generation Owner.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 9/14/2015

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Please see comment under Qustion 2 above.

Bob Thomas, 9/14/2015

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John Fontenot, 9/14/2015

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John Fontenot, 9/14/2015

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John Fontenot, 9/14/2015

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In our opinion there appears to be an inconsistency between the Standard and the Table of Compliance.  The Applicability section 4.1.1 identifies the Transmission Owner as a Functional entity.  Requirement R5 identifies the Transmission Owner with responsibility for confirming facilities are located within the BA boundaries.  However, in the Table of Compliance Elements for requirement R5, the Transmission Operator is identified with this responsibility under the Severe VSL column.  We believe that the Transmission Operator should be changed to Transmission Owner to be consistent with the requirements of the Standard.

 

David Jendras, Ameren - Ameren Services, 3, 9/14/2015

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see question2

FMPA, Segment(s) , 7/9/2015

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1.      R7 seems to not even fit with the stated purpose of FAC-001-3 for interconnecting (lowercase) to Facilities.  What is the purpose of R7?  Capitalized term “Interconnection” simply means “When capitalized, any one of the three major electric system networks in North America: Eastern, Western, and ERCOT.”  Reading the requirement at face value…if your load is anywhere in Eastern, Western , or ERCOT Interconnection area then confirm its in a BA Area’s metered boundaries.  Is the intent of R7 to identify which BA area the load is in?  or is the intent to simply identify “yes” it is in “a BAs Area’s metered boundary”?  How does knowing or not knowing this have adverse impacts on the reliability of the BES with respect to the purpose of the standard?

In addition, note that from NERC’s filing to FERC – Supplemental Information to Petition for Approval of Proposed Transmission Operations and Interconnection Reliability Operations and Coordination Reliability Standards, RM15-16, dated May 12, 2015 – NERC states that “An LSE does not own or operate Bulk Electric System facilities or equipment or the facilities or equipment used to serve end-use customers.21  (footnote 21 - The Distribution Provider is the functional entity that provides facilities that interconnect an end-use customer load and the electric system for the transfer of electrical energy to the end-use customer. If a company registered as an LSE also owned facilities, the company would be registered for other functions as well.  

 

2.      Measure M7 implies that LSEs have Facility interconnection requirements when there are no such requirements, thus complicating complying with R7.  Does the drafting team intend for the LSE to provide a copy of the Facility interconnection requirements documents they may have received from the TO when requesting to interconnect to the transmission owner?

3.      Depending on understanding the true intent of this requirement, we would be in favor for an attestation to be included in the measure, but then … seems like a pointless, administrative requirement that meets P81.

Scott McGough, Georgia System Operations Corporation, 3, 9/14/2015

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Mark Holman, 9/14/2015

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Chantal Mazza, On Behalf of: Hydro-Qu?bec TransEnergie - NPCC - Segments 2

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Theresa Rakowsky, 9/14/2015

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Duke Energy , Segment(s) 1, 5, 6, 4/10/2014

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Andrea Basinski, 9/14/2015

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LG&E and KU Energy, LLC, Segment(s) 1, 3, 5, 6, 9/11/2015

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KCP&L incorporates by reference its response to Survey Question No. 2.

Douglas Webb, 9/14/2015

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Matthew Beilfuss, On Behalf of: WEC Energy Group, Inc., MRO, RF, Segments 3, 4, 5, 6

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Given that NERC is in the process of delisting the LSE from the Functional Model and the NERC registry, suggest revising Requirement R7 to read “Each Distribution Provider that provides facilities that interconnect a customer Load shall confirm that each customer Load is within a Balancing Authority Area’s metered boundaries.” Measure M7 would need to be revised accordingly.

This standard is unnecessary given the fact that Interconnection Agreements are contractual legal documents that address and spell out the details addressed by the various FAC-001 requirements.

Also, the use of the requirement “shall address” is not a clear mandate and is open to interpretation by both the Responsible Entity and the Regional Enforcement entity.

The wording in Measures M5 thru M7 appear to have been copied from Measures M3 and M4, mentioning “dated, documented Facility interconnection requirements addressing the procedures” as evidence that the requirements are met. The wording in these Measures is appropriate for M3 and M4, but not M5 thru M7. 

 

NPCC--Project 2010-14.2.1 Phase 2 of Bal Auth Rel-based Controls - BAL-005-1, BAL-006-3, FAC-001-3 , Segment(s) 10, 3, 2, 1, 9, 6, 5, 8, 9/14/2015

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In addition to the comments GTC listed in Question 2, GTC believes the response to R5 as a TO would simply be "yes" and is unaware how this answer enhances reliable operation of the BES.  Therefore, GTC does not quite understand the intent of these requirements as they are written.  Confirm which BA Area the Transmission Facility is located in?  Confirm to whom?  GTC see's this as administrative in nature subject to P81 criteria.

Jason Snodgrass, 9/14/2015

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We appreciate the work by the SDT, but do not agree with moving BAL-005-0.2b Requirement R1 to FAC-001-3 Requirements R5, R6, and R7. At this time, the way the BAL-005 requirement R1 reads it poses to be more of an accounting issue versus a reliability issue. One alternative solution is to remove the language from this standard (FAC-001-3) and include it in the Application Guidelines section.

Mike ONeil, NextEra Energy - Florida Power and Light Co., 1, 9/14/2015

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Hydro One supports all comments provided by NPCC RSC regarding the draft of FAC-001-3.

Payam Farahbakhsh, Hydro One Networks, Inc., 1, 9/14/2015

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The SRC recommends that FAC-001-2 be retired

 

See file attached to Question 1 for the full text of the comments to Question 6

ISO Standards Review Committee, Segment(s) 2, 9/14/2015

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None.

Andrea Jessup, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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Again to illustrate the comments in response #2, FAC-001 is a facility interconnection requirement standard so any changes here will be applied to FAC-001 applicable functional entities documented facility interconnection requirements.  FAC-001 typically deals with new interconnections, so if the intent of the FAC-001-3 R5-R7 is to make sure all transmission, generation, and load are within a BAA metered bounds this is not the correct standard. R7 in its entirety needs to be moved to another standard since it is not clear which interconnection requirement it will fall under (i.e. TO and/or Applicable GO).

 

The FAC-001 standard can be used to require documented facility interconnection requirements to address BAA metered bounds for all entities seeking to interconnect. However to enforce this for BAA metered bounds for those facilities that already exist within FAC-001, the documented facility interconnection requirements would have to retroactively apply for those facilities that already exist. R5-R6 needs to be moved to another standard.

Colorado Springs Utilities, Segment(s) 1, 6, 3, 5, 9/14/2015

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