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 Individual or group.NameOrganizationGroup NameLead ContactContact OrganizationQuestion 1Question 2Question 2 CommentsQuestion 3Question 3 CommentsQuestion 4 Comments
Group  WECC Market Interface Committee / Sub Commtt / ATC Task ForceW. Shannon BlackSMUDErrata: MOD-29, R.1.1.1.2 and R.1.1.1.3, the word equivalent should be capitalized. MOD-29, M7 and M8 as drafted require the TSP to be "capable" of demonstration but do not require actual demonstration. The WECC Team suggests a minor rewrite to state, "The TSP shall demonstrate that..." This shifts the measurement from the TSP's mere capability to an actual performance. Yes Yes The WECC Team notes that changing the modeling equivalence threshold within MOD-29 to match that of the other methodologies creates a seamless and equal application across all methodologies for all of NERC.
IndividualJack Cashin/Barry GreenEPSA   Through this revision process, some of the MOD standards have included an explicit requirement for consistency between planning assumptions and modeling assumptions used in calculation of ATC. We believe this is appropriate and should be included in MOD 029.  no comment no commentno comment
IndividualJim UseldingerKansas City Power & Light   The Transmission Service Provider should be added along with the TOP for these functions in all requirementsYes Yes  
IndividualPaul RochaCenterPoint Energy        The group of standards is for ATC and TRM methodologies that are not used in ERCOT. CenterPoint Energy is concerned that ERCOT might have to adopt the ATC and TRM methodologies prescribed in these standards, which we believe would not add value to the ERCOT region and could increase congestion in the region. Accordingly, CenterPoint Energy previously submitted comments to these standards asking for an exemption for the ERCOT region. We find the proposed standards unacceptable unless the following provision is added to each standard: This standard does not apply to ERCOT or any other region that operates as a single control area.
Group  WECC Market Interface Committee ATC Task ForceW. Shannon BlackSMUD Errata: MOD-29, R.1.1.1.2 and R.1.1.1.3, the word equivalent should be capitalized. MOD-29, M7 and M8 as drafted require the TSP to be "capable" of demonstration but do not require actual demonstration. The WECC Team suggests a minor rewrite to state, "The TSP shall demonstrate that..." This shifts the measurement from the TSP's mere capability to an actual performance. Yes Yes The WECC Team notes that changing the modeling equivalence threshold within MOD-29 to match that of the other methodologies creates a seamless and equal application across all methodologies for all of NERC.
IndividualH. Steven MyersERCOT ISO   Requirement 1: I suggest modifying the requirement to state: "When calculating TTCs for ATC Paths, the Transmission Operator with ATC Path(s) shall use a Transmission model which satisfies the following requirements:" Requirement 2: I suggest modifying the requirement to state: "The Transmission Operator with ATC Path(s) shall use the following process to determine TTC:" Requirement 3: I suggest modifying the requirement to state: "Each Transmission Operator with ATC Path(s) shall establish the TTC at the lesser of the value calculated in R2 or any System Operating Limit (SOL) for that ATC Path." Requirement 4: I suggest modifying the requirement to state: "Within seven calendar days of the finalization of the study report, the Transmission Operator with ATC Path(s) shall make available to the Transmission Service Provider of the ATC Path, the most current value for TTC and the TTC study report documenting the assumptions used and steps taken in determining the current value for TTC for that ATC Path." Requirement 5: I suggest modifying the requirement to state: "When calculating ETC for firm Existing Transmission Commitments (ETCF) for a specified period for an ATC Path, the Transmission Service Provider with ATC Path(s) shall use the algorithm below:" Requirement 6: I suggest modifying the requirement to state: "When calculating ETC for non-firm Existing Transmission Commitments (ETCNF) for all time horizons for an ATC Path the Transmission Service Provider with ATC Path(s) shall use the following algorithm:" Requirement 7: I suggest modifying the requirement to state: "When calculating firm ATC for an ATC Path for a specified period, the Transmission Service Provider with ATC Path(s) shall use the following algorithm:" Requirement 8: I suggest modifying the requirement to state: "When calculating non-firm ATC for an ATC Path for a specified period, the Transmission Service Provider with ATC Path(s) shall use the following algorithm:"    I suggest mofifying the Applicability section to state" "4.1. Each Transmission Operator with ATC Path(s) that uses the Rated System Path Methodology to calculate Total Transfer Capabilities (TTCs) for ATC Paths." "4.2. Each Transmission Service Provider with ATC Path(s) that uses the Rated System Path Methodology to calculate Available Transfer Capabilities (ATCs) for ATC Paths."
Group  NPCC Reliability Standards CommitteeGuy V. ZitoNorthast Power Coordinating CouncilNPCC Participating Members have the following comments on the Requirements and Measures: a. M1.1: The term “in its ATC calculations” is inappropriate and “its” should be removed. b. M7: This measure corresponds to R5, which stipulates the use of a specific algorithm. However, M7 provides the requirement for certain accuracy, which leads to the following questions i. Is R5 about the use of an algorithm only or is it also about the proper or consistent setting of the variables within that algorithm? ii. If it is also the proper or consistent setting of the variables, the requirement should stipulate the conditions rather than leaving the assessment to a recalculation process (stipulated in M7) to determine if the algorithm and its settings have been properly used. iii. If accuracy is to be a criterion for having proper and consistent setting of the variables, it becomes a requirement and hence should be stipulated in the requirement section, not in the measure. c. M8: Same comment on M7 also applies here for R6. d. The current wording on R2.4 and R2.5 can be viewed as conflicting and the language should be modified. R2.4 implies that ATC Paths can impact each other, hence the purpose for a nomogram. However, then R2.5 says that the TTC on an ATC Path cannot adversely impact the TTC of an existing path – that would imply that nomograms would never be required. In addition, R2.5 requires one specific approach to handling the condition where a ‘new’ study impacts an existing path. When, in reality, there are often contractual arrangements that would govern how that issue would be resolved where that resolution could be different than the approach defined in R2.5 and just as reliable. An example of that is when a ‘new’ path has an impact on an ‘old’ path, where ‘old path’ has no requests for service and the ‘new path’ will be in high demand. The following is our suggested language. The additional detail that we are suggesting be removed, the default resolution process, can be added to local procedures. 2.5 Transmission Operator shall identify when the TTC for the ATC Path being studied adversely impacts the TTC value of any existing path. The Transmission Operator shall include their resolution of this adverse impact in the study report for the ATC Path. Yes Yes  
IndividualThad NessAEP   R1.1.1 possible English issue, Does the requirement allow that all radial lines be equivalents and that ALL facilities 161 kV and lower voltage may also be equivalents? R.2.1.1 Was the intent that the ‘base case’ contain no loading above the respective normal rating, rather than the literal remove any overloaded line from the model?     The Applicability of this Standard should be solely upon the TSP, the Transmission Operator should not be subject to this Standard. From the previous set of responses, it is the apparent belief of the SDT that the calculation of ATC is needed for reliability (response to AECI for example). We disagree. Considering that ATC is a mathematical amalgamation of forecasted system conditions (load, outages, generation dispatch, others’ transactions, etc) compounded and adjusted by margins (TRM and CBM of own entity and other systems), using the calculated ATC to assess real or near real time transmission reliability would be – at best – unwise. Transmission Reliability can be assessed by monitoring specific and individual Facility loadings and/or other parameters, for example. The calculation of ATC and the value of resultant ATC is exactly for the purpose stated in the definition of ATC: “A measure of … capability….for further commercial activity” – and note the definition does not infer ATC is a measure of reliability. Granted, ATC is calculated FROM reliability derived values and concepts (such as ratings, contingency analysis aspects, SOLs etc), BUT the resultant ATC values are not an assessment of transmission reliability – and therefore not a function for the Transmission Operators, but rather the Transmission Service Provider. In addition, the Purpose statement is unclear and perhaps nonsensical. Is the purpose “to increase consistency and reliability in the development of documentation….” or “to support analysis and system operation”? What entities’ “short term use”? Suggestion: Purpose: To ensure consistency of calculation of those entities employing Rated System Path Methodology pursuant to MOD-001 R1.
Group  Public Service Commission of South CarolinaPhil RileyPublic Service Commission of South Carolina Yes Yes  
IndividualGreg RowlandDuke Energy Corporation   R1.1 - Bulk electric system facilities 161kV and below may have significant network response. Since these facilities may have significant impact on TTC, documentation should be required by the standard for those facilities 161kV and below which are equivalized. This will provide transparency for impacted stakeholders. R2.8 - Need to ensure that comparable information should be required in either the study report or the ATCID in MOD-028, MOD-029 and MOD-030. Yes Yes  
IndividualPatrick Brown PJM   PJM does not have any specific comments.YesPJM supports NERC’s position to revise all Violation Risk Factors to have an assigned risk factor of “Lower.” A Lower Risk Factor requirement is administrative in nature and is a requirement that, if violated, would not be expected to affect the electrical state or capability of the bulk power system, or the ability to effectively monitor and control the bulk power system.NoNERC states that a VSL defines the degree to which compliance with a requirement was not achieved. The violation severity levels for these draft standards now, for the most part, have a graded implementation, but PJM has a concern regarding the possibility of multiple violations resulting from a single event. PJM requests that double counting of violations for a single event be eliminated. A single event shall not result in multiple violations –this language to be added to the standard. PJM reiterates that while we will not choose the calculation methodologies used in MODs 28 and 29, these MODs will require modification to assure consistency with any revisions made to MOD 30. PJM is including specific comments for MOD 30 in Section VI of this document. PJM is not providing specific comments for MODs 28 and 29.
IndividualGreg Ward / Darryl CurtisOncor Electric Delivery   All schedules in ERCOT flow with no pre-defined paths and any congestion is mitigated by market mechanisms and/or verbal dispatch instructions from ERCOT (in the case of an emergency). Oncor is concerned about the risk of ERCOT being found in non-compliance with the underlying standard due to the methodologies not being a part of the ERCOT market. Furthermore, Oncor believes that implementation of the prescribed methodologies would add no value to the ERCOT market and could result in more system congestion. Oncor strongly suggests that this standard specify that it is not applicable to regions with a single control area and no defined ATC path(s).Yes Yes This standard should not apply to ERCOT for the reason expressed in question 1.
Group  Bonneville PowerDenise KoehnTransmission Reliability ProgramBPA does not believe any are incorrect.Yes Yes BPA respectfully submits the following observations and suggestions: a. Including counterflows in the calculation of firm ATC is not appropriate because it could result in exceeding a TTC limit due to forced outage scenarios. An accurate estimation of counterflows cannot be assured and may result in over selling transmission. R7 should be modified to state that for firm ATC calculations counterflows shall always be zero. b. The Time Horizons listed for all requirements should include the “Long-term Planning” Horizon, as ATC is to be calculated beyond the seasonal window. c. Balancing Authorities may be appropriately identified as Applicable Entities in this MOD and request that the Standards Drafting Team provide an explanation as to why they are not listed.
IndividualRichard KafkaPepco Holdings, Inc   PHI supports the comments of PJM and will not submit duplicate comments     
IndividualAlice DruffelXcel Energy   R2.5 reads: Verify that the TTC for the ATC Path being studied does not adversely impact the TTC value of any existing path. Do this by modeling the flow on the path being studied at its proposed new TTC level simultaneous with the flow on the existing path at its TTC level while at the same time honoring the reliability criteria outlined in R2.1. We feel this requirement may be, in some cases, impractical to meet due to lack of resources (generation) to simultaneously load two paths (existing and new) to their TTC limits. We suggest that the 2nd sentence of this requirement be reworded something like this: "Do this by modeling the flow on the path being studied at its proposed new TTC level simultaneous with the flow on the existing path at its highest achieveable TTC level, up to the existing path's TTC limit, with a realistic generation dispatch while at the same time honoring the reliaibility criteria outlined in R2.1".Yes Yes  
IndividualRon FalsettiOntario IESO   1. We have the following comments on the Requirements and Measures: a. R3: Should the “or” before “any system operating limits” be an “and” to go along with the requirement that stipulates picking the lesser value of two? Same change applies to M5, and VSLs for R3. b. M1.1: We do not understand the basis for this measure, in particular the form and format. They are not specified in the requirement. Further, the TOP does not calculate ATC; the term “in its ATC calculations” is inappropriate. c. M1.2: There seems to be an extra “1” after R1.1.1. d. M7: This measure corresponds to R5, which stipulates the use of a specific algorithm. However, M7 provides the requirement for certain accuracy, which leads to the following questions: i. Is R5 about the use of an algorithm only or is it also about the proper or consistent setting of the variables within that algorithm? ii. If it is also the proper or consistent setting of the variables, the requirement should stipulate the conditions rather than leaving the assessment to a recalculation process (stipulated in M7) to determine if the algorithm and its settings have been properly used. ii. If accuracy is to be a criterion for having proper and consistent setting of the variables, it becomes a requirement and hence should be stipulated in the requirement section, not in the measure. e. M8: Same comment on M7 also applies here for R6. f. The current wording on R2.4 and R2.5 can be viewed as conflicting and the language should be modified. R2.4 implies that ATC Paths can impact each other, hence the purpose for a nomogram. However, then R2.5 says that the TTC on an ATC Path cannot adversely impact the TTC of an existing path – that would imply that nomograms would never be required. In addition, R2.5 requires one specific approach to handling the condition where a ‘new’ study impacts an existing path. When, in reality, there are often contractual arrangements that would govern how that issue would be resolved where that resolution could be different than the approach defined in R2.5 and just as reliable. An example of that is when a ‘new’ path has an impact on an ‘old’ path, where ‘old path’ has no requests for service and the ‘new path’ will be in high demand. The following is our suggested language. The additional detail that we are suggesting be removed, the default resolution process, can be added to local procedures. 2.5 Transmission Operator shall identify when the TTC for the ATC Path being studied adversely impacts the TTC value of any existing path. The Transmission Operator shall include their resolution of this adverse impact in the study report for the ATC Path. NoThose requirements (at least R2 and R3) that hold the TOP responsible for establishing TTCs should be assigned a Medium since TTCs set the reliability boundary, like an SOL or IROL, within which the TSP may provide transmission services. Failure to establish TTCs may result in the TSP over-selling transmission services beyond the reliability bounds, risking the BES to unreliable operation.NoWe do not agree with the following VSLs: a. R1 has two subrequirements: R1.1 for modeling details and R1.2 for use of facility ratings provided by the owners. A total failure of R1 would be failing both subrequirements. On this basis, we agree with the Low and Moderate but do not agree with the Severe which if changed, can impact the High VSL as well. For Severe, we suggest to change the condition to “AND” instead of “OR”. And with this change, the High would thus be for “3 or more” in the first condition and “21 or more” in the second condition, and the same language apply to the conditions for Severe, or something along that line in terms of the threshold numbers. b. There are 2 measures developed for R2 – an M3 for R2.7 and an M4 for the rest of R2 including R2.8 (a report that shows the process detailed in R2.1 to R2.6 was followed). Yet the VSL only has one entry, which appears to treat R2 as a binary requirement. There are at least two issues with this lone VSL: 1. M3 and M4 become irrelevant 2. There is no provision for progressive (graded) VSLs for failing any of the subrequirements c. We suggest the SDT review the measures in conjunction with the VSLs for this requirement. At a minimum, the VSLs should be dependent on the number of subrequirements not met. If the SDT wishes to have a simple set of VSLs, it may consider eliminating M3 hence making all subrequirements binary to support a progressive (graded) VSL for the main requirement. d. R5: For these VSLs to be appropriate, please see our comments and suggestion for changes on M7 under Q1. e. R6: For these VSLs to be appropriate, please see our comments and suggestion for changes on M8 under Q1. None
Group  IRC Standards Review CommitteeCharles YeungSouthwest Power Pool1. We have the following comments on the Requirements and Measures: a. R3: Should the “or” before “any system operating limits” be an “and” to go along with the requirement that stipulates picking the lesser value of two? Same change applies to M5, and VSLs for R3. b. M1.1: We do not understand the basis for this measure, in particular the form and format. They are not specified in the requirement. Further, the TOP does not calculate ATC; the term “in its ATC calculations” is inappropriate. c. M1.2: There seems to be an extra “1” after R1.1.1. d. M7: This measure corresponds to R5, which stipulates the use of a specific algorithm. However, M7 provides the requirement for certain accuracy, which leads to the following questions i. Is R5 about the use of an algorithm only or is it also about the proper or consistent setting of the variables within that algorithm? ii. If it is also the proper or consistent setting of the variables, the requirement should stipulate the conditions rather than leaving the assessment to a recalculation process (stipulated in M7) to determine if the algorithm and its settings have been properly used. ii. If accuracy is to be a criterion for having proper and consistent setting of the variables, it becomes a requirement and hence should be stipulated in the requirement section, not in the measure. e. M8: Same comment on M7 also applies here for R6. NoNo, those requirements (at least R2 and R3) that hold the TOP responsible for establishing TTCs should be assigned a Medium since TTCs set the reliability boundary, like an SOL or IROL, within which the TSP may provide transmission services. Failure to establish TTCs may result in risking the BES to unreliable operation.NoWe do not agree with the following VSLs: a. R1: R1 has two subrequirements: R1.1 for modeling details and R1.2 for use of facility ratings provided by the owners. A total failure of R1 would be failing both subrequirements. On this basis, we agree with the Low and Moderate but do not agree with the Severe which if changed, can impact the High VSL as well. For Severe, we suggest to change the condition to “AND” instead of “OR”. And with this change, the High would thus be for “3 or more” in the first condition and “21 or more” in the second condition, and the same language apply to the conditions for Severe, or something along that line in terms of the threshold numbers. b. R2: There are 2 measures developed for R2 – an M3 for R2.7 and an M4 for the rest of R2 including R2.8 (a report that shows the process detailed in R2.1 to R2.6 was followed). Yet the VSL only has one entry, which appears to treat R2 as a binary requirement. There are at least two issues with this lone VSL: i. M3 and M4 become irrelevant ii. There is no provision for progressive (graded) VSLs for failing any of the subrequirements We suggest the SDT review the measures in conjunction with the VSLs for this requirement. At a minimum, the VSLs should be dependent on the number of subrequirements not met. If the SDT wishes to have a simple set of VSLs, it may consider eliminating M3 hence making all subrequirements binary to support a progressive (graded) VSL for the main requirement. c. R5: For these VSLs to be appropriate, please see our comments and suggestion for changes on M7 under Q1. d. R6: For these VSLs to be appropriate, please see our comments and suggestion for changes on M8 under Q1.  
IndividualRex McDanielTexas-New Mexico Power Company   All schedules in ERCOT flow with no pre-defined paths and any congestion is mitigated by market mechanisms and/or verbal dispatch instructions from ERCOT (in the case of an emergency). Texas-New Mexico Power Company is concerned about the risk of ERCOT being found in non-compliance with the underlying standard due to the methodologies not being a part of the ERCOT market. Furthermore, TNMP believes that implementation of the prescribed methodologies would add no value to the ERCOT market and could result in more system congestion. TNMP strongly suggests that this standard specify that it is not applicable to regions with a single control area and no defined ATC path(s).Yes Yes This standard does not apply to ERCOT for the reason stated in Question 1.
Group  PPL Supply GroupAnnette BannonPPL Generation     The extent to which standard MOD-029 is able to attain consistency in calculating ATC in-part depends on the definitions of terms used in the formulas. Unfortunately, the definition of the word “commitment” is not specific enough to be useful. In fact, the same phrase (“existing transmission commitment”) is calculated differently in R5 than R6. For this reason, the term “ETC” should be dropped from standard MOD-029 and defined terms used. R6 defines PTP Non-Firm as including reserved capacity and should only include tagged or scheduled capacity. Capacity that is reserved but not scheduled should not affect NF ATC. It is also important that the same time periods be used to define the three time periods (scheduling horizon, operating horizon, and planning horizon) within an interconnect (i.e. the WECC) so that the same ATC algorithm is applied in all BA’s across an interconnect for the same hour.
Group  PacifiCorpShay LaBrayPacifiCorpPacifiCorp provided comments on March 12, 2008 related to the reference to counterflows in MOD-029, Rated System Path Methodology. In its comments, PacifiCorp relayed its concern that most transmission providers in the West, including PacifiCorp, using the Rated System Path Methodology do not use counterflows as defined in the formula for calculating increment firm ATC. The April 16, 2008 modified version of MOD-029 appears to address this concern by including language in M9 and M10 stating that: “Such documentation must show that only the variables allowed in R7 [R8 in M10] were used to calculate firm ATCs, and that the processes use the current values for the variables as determined in the requirements or definitions. Note that any variable may legitimately be zero if the value is not applicable or calculated to be zero (such as counterflows, TRM, CBM, etc.).” In order to ensure consistency with the above, PacifiCorp recommends the below modifications to the associated violation severity levels for R7 and R8 and the definition of Rated System Path Methodology. The recommended recognizes that future utility personnel and audit staff that do not have the benefit of participation in this process and record can clearly understand that counterflows and postbacks may be used as determined by the Transmission Provider, and the necessary documentation only applies to components used in the ATC calculation. Specifically, 1. The violation severity level for R7 and R8 should be revised to read: "The Transmission Service Provider did not use all the elements defined and applicable in R7 when determining firm ATC, or used additional elements" or our earlier suggested revision "The Transmission Service Provider did not use all the elements defined in R7 and as specified in the Transmission Service Provider's Available Transfer Capability Implementation Document required in MOD-001, when determining firm ATC, or used additional elements." 2. In order to ensure consistency with the way counterflows are addressed, the definition of Rated System Path Methodology should include the words “as applicable” after the new inserted language “and postbacks and counterflows are added.” The revised language would read as follows: Rated System Path Methodology: The Rated System Path Methodology is characterized by an initial Total Transfer Capability (TTC), determined via simulation. Capacity Benefit Margin, Transmission Reliability Margin, and Existing Transmission Commitments are subtracted from TTC, and Postbacks and counterflows are added as applicable to derive Available Transfer Capability. Under the Rated System Path Methodology, TTC results are generally reported as specific transmission path capabilities. These changes ensure consistency and clarity of the standard that a utility is not required to apply counterflows to its firm ATC calculation.      
Group  Electric Service DeliveryReza EbrahimianAustin Energy      These comments are filed on behalf of City of Austin d/b/a Austin Energy to address proposed NERC 5 MOD Standards. Austin Energy is a municipally owned electric utility and a transmission service provider with the Electric Reliability Council of Texas (ERCOT). ERCOT now operates as a Single Balancing Authority with no explicit transmission services being sold. Current ERCOT market rules allow open transmission access to all loads and resources. ERCOT will continue to operate as a Single Balancing Authority under Nodal market design. Accordingly, as explained in more detail below, the NERC 5 MOD Standards should not be applied to ERCOT and transmission service providers within ERCOT under its current or proposed Nodal market design. Austin Energy requests that the NERC Standards Drafting team add language to these Standards to clarify that MOD-001-1, MOD-008-1, MOD-028-1, MOD-029-1, and MOD-030-1 Standards are not applicable to regions with a Single Balancing Authority that do not use ATC methodology and any of its components in their market operations. Applicable definitions: According to NERC Reliability Standards Glossary of Terms, Available Transfer Capability (ATC) is defined as: “A measure of the transfer capability remaining in the physical transmission network for further commercial activity over and above already committed uses. It is defined as Total Transfer Capability (TTC) less existing transmission commitments (including retail customer service), less a Capacity Benefit Margin (CBM), less a Transmission Reliability Margin (TRM), plus Postbacks, plus counterflows”. TTC is defined as: the amount of electric power that can be transferred over the interconnected transmission network in a reliable manner while meeting all of a specific set of defined pre- and post-contingency system conditions. CBM is defined as the amount of transmission transfer capability reserved by load serving entities to ensure access to generation from interconnected systems to meet generation reliability requirements. TRM also is a component of ATC defined as: that amount of transmission transfer capability necessary to ensure that the interconnected transmission network is secure under a reasonable range of uncertainties in system conditions. Comments: ERCOT is an interconnection and a region with no synchronous AC ties with any other interconnections. In July 2001, based on a deregulated Retail and restructured Wholesale Markets, the ERCOT interconnection began acting as a Single Balancing Authority. The ERCOT market is designed such that there are no explicit transmission services being sold, hence, Available Transfer Capability (ATC) is not a measure used in a commercial activity within the ERCOT market. The current ERCOT market rules allow open transmission access to all eligible loads and resources without considering any specific Transmission Service Provider (TSP). Transmission facilities ratings are based upon individual branch element designs and in cases of dynamic ratings, ambient conditions are also considered. ERCOT has several DC ties and an asynchronous tie using a Variable Frequency Transformer (VFT); however, the associated interchange capabilities are planned and coordinated by the TSPs involved. The current ERCOT Zonal Market uses a flow based congestion management methodology to predict potential congestions in the Day Ahead and Adjustment Periods. During the operating period, generation shift factors are used to determine the dispatch needed to remain within the constrained limits. The local congestions are managed using full AC load flow analysis and unit specific redispatch. MOD-001-1 is entirely about methodology and calculation of ATC, therefore, this standard is not applicable to ERCOT. MOD-008-1 covers Transmission Reliability Margin (TRM) methodology calculation. Mathematically, ATC is defined as Total Transfer Capability (TTC) less the TRM and Capacity Benefit Margin (CBM). Therefore, TRM also is not applicable to ERCOT. MOD-028-1 covers Area Interchange calculation Methodology. Since ERCOT is a single control area, Area Interchange calculation is not applicable. MOD-029-1 covers Rated System Path Methodology, which is used to calculate TTC and ATC calculations. Therefore MOD-029-1 is not applicable to ERCOT. MOD-030-1 covers Flowgate methodology calculation of ATC, and therefore, is not applicable to ERCOT. ERCOT is currently transitioning to a Nodal Market, with a scheduled start date of December 1, 2008. The Nodal Market uses a Security Constrained Economic Dispatch (SCED) approach to dispatch individual generating units and manage congestion. In the Nodal Market, ERCOT will still operate as a Single Balancing Authority. This again will not use ATC methodology, and aforementioned standards are not applicable to ERCOT in its ensuing Nodal Market. Therefore, Austin Energy requests that the NERC Standards Drafting team add language to these Standards to clarify that MOD-001-1, MOD-008-1, MOD-028-1, MOD-029-1, and MOD-030-1 Standards are not applicable to regions with a Single Balancing Authority that do not use ATC methodology and any of its components in their market operations.
IndividualAllen MosherAmerican Public Power Association   The Rated System Path Methodology definition, like Area Interchange and Flowgate, includes the text: "Capacity Benefit Margin, Transmission Reliability Margin, and Existing Transmission Commitments are subtracted from the TTC, and Postbacks and counterflows are added, to derive Available Transfer Capability." This text describes the derivation of ATC or AFC, and should not be part of a definition to differentiate between the AIM, RSP and Flowgate methods. R1.1.1 - I support allowing "Equivalent representation of radial lines and facilities 161 kV or below" but equivalences for elements that are included in the regionally definition of the BES should be explained in the ATCID. Additional detail is appropriate if eliminating an equivalence has a material impact on transfer capability. R1.1.3. Requires the Transmission Operator to “[Model] all generation Facilities larger than 20 MVA in the studied area.” The NERC Glossary defines Facility as: A set of electrical equipment that operates as a single Bulk Electric System Element (e.g., a line, a generator, a shunt compensator, transformer, etc.). Thus this requirement refers to a single generator connected to the BES, rather than a station or project. R1.1.3 does not literally require modeling of wind and other renewable generation projects because each unit may only be 1.5 MW. Yet such projects are likely to be the modeled source for Interchange Transactions. Conversely, generation that is connected to non-BES subtransmission or distribution network facilities that is used to serve local load may not have a material impact on Rated System Path TTC and ATC. I suggest a hybrid definition that is consistent with the Compliance Registry Criteria but allows for additional detail as required: “Models all generation units larger than 20 MVA and generation projects larger than 75 MVA in the studied area that are directly connected to the Bulk Electric System. Modeling of additional generation Facilities shall be addressed in the ATCID.” R5 and R6 – Definition of “GF” Grandfathered Firm/Non-Firm Transmission Service – please delete “accepted by FERC” after “Safe Harbor Tariff.” FERC regulatory approval of a tariff for rate purposes is not relevant to what form of transmission service tariff a NERC TSP provides. Many U.S. utilities are not FERC jurisdictional for electric rate purposes. All Canadian TSPs are non-jurisdictional. R7 and R8 - Postbacks and counterflows: “Counterflows” should be a defined term. It is used in MOD-1, MOD-28, MOD-29 and MOD-30 and is an integral element in the calculation of ATC and AFC. The definition used in MOD-29-1 R7, for example, reads: “CounterflowsF are adjustments to firm Available Transfer Capability as determined by the Transmission Service Provider and specified in their ATCID.” This definition does not in any way describe what a counterflow is. “Postbacks” should incorporate a working definition developed by NAESB, to be revised once due process is completed on this business practice. Alternatively, consider use of the following text to at minimum describe the nature of postbacks: “Postbacks[Firm][Non-Firm] are changes to firm [non-firm] ATC [AFC] due to a change in the amount of Firm [non-firm] Transmission Service reserved or scheduled for a period, as defined in Business Practices. Postbacks are generally a positive quantity.” Also, include Postbacks in the "e.g." list of factors in M9 and M10. Yes Yes Excellent work
IndividualRick GonzalesNew York Independent System Operator   The NYISO has previously commented that it is critically important to it that the algorithm for calculating “Existing Transmission Commitments” (“ETC”) in MOD-029 (and -028) be interpreted flexibly. The NYISO’s existing ATC calculation procedure, which reflects the nature of its financial reservation system, and which has been accepted by the Commission, is to calculate firm and non-firm ATC as follows: ATC(Firm) = TTC – Transmission Flow Utilization(Firm) – TRM ATC(Non-Firm) = ATC(Firm) – Transmission Flow Utilization(Non-Firm) Where “Transmission Flow Utilization” represents the security constrained network powerflow solutions of the NYISO’s Security Constrained Unit Commitment software, with respect to the NYISO Day-Ahead Market, or its Real-Time Commitment and Real-Time Dispatch software with respect to the NYISO’s Real-Time Market. As the NYISO has explained in prior comments, it believes that the central role that Transmission Flow Utilization plays in its ATC/TTC calculations can be accommodated under proposed MOD-029 by accounting for it in the ETC calculation algorithms established under R5 and R6. Specifically, the SDT's proposed definition of the OS(F) variable appears to be broad enough to encompass Transmission Flow Utilization. The NYISO has previously requested that the SDT clarify or revise the OS(F) definition so that it would clearly allow the NYISO to account for Transmisison Flow Utilization in this way. The SDT has not yet responded. Accordingly, the NYISO requests that the the OS(F) definition under R5 be revised to read: OS(F) is the firm capacity reserved for any other service(s), contract(s), or agreement(s) not specified above using Firm Transmission Service, including any other firm adjustments to reflect impacts from other ATC Paths of the Transmission Service Provider as specified in the ATCID, including security constrained network powerflow solutions produced by market software used by Transmisison Service Providers that administer FERC-approved organized markets. Similarly, the OS(F) definition under R6 should be revised to read: OS(F) is the non-firm capacity reserved for any other service(s), contract(s), or agreement(s) not specified above using Non-Firm Transmission Service, including any other firm adjustments to reflect impacts from other ATC Paths of the Transmission Service Provider as specified in the ATCID, including security constrained network powerflow solutions produced by market software used by Transmisison Service Providers that administer FERC-approved organized markets. Making these revisions should have no impact on the vast majority of Transmission Service Providers, because they will neither administer FERC-approved organized markets nor use security constrained network powerflow solutions produced by market software in their ATC/TTC calculations. On the other hand, the revisions would permit the NYISO to come into compliance with NERC's proposed MOD standards without having to make fundamental changes to its FERC-approved market design or financial reservation transmission model. Order No. 890 was clear that it would not require fundamental changes to ISO/RTO market designs. This principle was recently upheld when FERC accepted the NYISO's Order No. 890 tariff compliance filing without requiring any changes to its financial reservation transmission model. The NYISO asks that the SDT make the requested revisions in order to elimiante any possibility of a conflict between the NYISO's FERC approved system and the NERC MOD standards. The NYISO recognizes that the definition of OS(F) may already be broad enough to accommodate Transmission Flow Utilization. If the SDT does not make the requested revision the NYISO will take the position that it may describe its use of Transmission Flow Utilization in the ETC calculation within its ATCID. Nevertheless, because this issue is so important to the NYISO's future compliance with NERC's MOD standards the NYISO would strongly prefer that the issue be expressly addressed within the text of MOD-029 and (MOD-028). The NYISO may raise the issue at FERC if it is not addressed by NERC.      
IndividualTony KroskeyBrazos Electric Power Cooperative, Inc.        Brazos Electric believes that the concept of the Rated System Path Methodology is not applicable to a single-control area operation like ERCOT. To address this issue, the Applicability section could have a clarifying statement that only TOPs or TSPs that conduct area to area operations and hence have have responsibility for ATC Path(s) must have a Rated System Path Methodology to support analysis and system operations.