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 Individual or group.NameOrganizationGroup NameLead ContactQuestion 1Question 1 CommentsQuestion 2Question 3Question 3 CommentsQuestion 4Question 4 CommentsQuestion 5 Comments
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  SERC ATCWGDoug BaileyNo preference  Yes Yes  
IndividualJack Cashin/Barry GreenEPSA  No preference We believe that the former requirement R1.2 which established the consistency between planning assumptions and those used in calculation TRM was appropriate and do not agree with its deletion. In R3, the previous draft of the standard required sharing of "underlying documentation, work papers and load flow base cases". In the current draft, the latter two of the listed items have been deleted. It is acceptable to us if this is done merely because they are deemed to be redundant as they are included within the meaning of "underlying documentation". If this was not the intent of the drafters, we would disagree with this change as those are items that would be required in order to reproduce the studies that have led to the posted ATC values. no comment no commentThis comment relates also to the NAESB recommendation that no additional business practices related to TRM will be developed. Our comments are based also on Order 890 Paragraph 207 which states in part: "The purpose of increasing the consistency and transparency of ATC calculations is to reduce the potential for undue discrimination in the provision of transmission service, specifically by reducing the opportunity for transmission providers to exercise excessive discretion. We find that the amount of discretion in the existing ATC calculation methodologies gives transmission providers the ability and opportunity to unduly discriminate against third parties. In order to minimize this discretion, the Final Rule requires that all ATC components (i.e., TTC, ETC, CBM, and TRM) and certain data inputs, data exchange, and assumptions be consistent and that the number of industry-wide ATC calculation formulas be few in number, transparent and produce equivalent results." EPSA does not believe that the mandate given by FERC to NERC and to NAESB has been carried out. EPSA accepts that in calculating ATC, Transmission operators need a margin, which is deducted from the TTC or AFC as appropriate, to allow for uncertainties in forecast conditions and thus to insure that Transmission Service is not oversold. As it represents an allowance for uncertainties, it is recognized that TRM is based on assumptions about future conditions and is in general, determined probabilistically. However, based on the proposed actions of the two standards development organizations, in order to meet FERC’s Order to “increas[e] the consistency and transparency of ATC calculations” and to “reduc[e] the opportunity for transmission providers to exercise excessive discretion” the industry has provided standards that: • Require Transmission Operators to only identify various elements if they are used in establishing TRM. At no point in the standard however, is any direction provided on how the Transmission Operators determine whether or not to use the various components or, if used, how values are to be established. • Make no provision for monitoring or reporting on utilization of TRM • Make no provision for verifying from season to season or year to year whether the values utilized in establishing TRM were or remain appropriate. These standards therefore impose only a minimal requirement for transparency and no requirement for consistency in establishing TRM and no requirement to monitor its usage to verify that assumed values are appropriate. The current NERC and NAESB standards on TRM are reminiscent of the previous NERC standard on ATC which was developed in response to Order 888. It required only that Transmission Operators document their methodology for calculating ATC, much like other fill-in-the-blank standards. Clearly in approving Order 890 and more particularly in Order 693 where they declined to approve other industry fill-in-the-blank standards, FERC has determined that such a standard is insufficient. Yet, with respect to TRM, the industry, through NERC and NAESB, seems prepared to submit standards to FERC that demonstrate that very little progress has been made.
Group  WECC Market Interface Committee / Sub Commtt / ATC Task ForceW. Shannon BlackYes  The Team suggests moving the final phrase of the proposed R3 Requirement to the beginning of the sentence to add clarity. (This is a non-substantive change.) The new R would read: No more than 30 calendar days after receiving a request, each Transmission Operator shall make available its TRMID, and if requested, its underlying documentation (if any) used to determine TRM, in the format used by the Transmission Operator, to any of the following who make a written request for that data: Yes Yes  
IndividualJim UsedingerKansas City Power & Light  NoThe Transmission Service Provider should also be listed as an appropriate entity along with the TOP in all requirements, so that either entity could perform this function.Add "or Transmission Service Provider" after Transmission Operator in all requirements.Yes Yes  
Group  WECC Market Interface Committee ATC Task ForceW. Shannon BlackYes  The Team suggests moving the final phrase of the proposed R3 Requirement to the beginning of the sentence to add clarity. (This is a non-substantive change.) The new R would read: No more than 30 calendar days after receiving a request, each Transmission Operator shall make available its TRMID, and if requested, its underlying documentation (if any) used to determine TRM, in the format used by the Transmission Operator, to any of the following who make a written request for that data:Yes Yes  
IndividualH. Steven MyersERCOT ISO  No preference Requirement 1: I suggest modifying the requirement to state: "Each Transmission Operator with ATC Path(s) and with TRM shall prepare and keep current a TRM Implementation Document (TRMID) that includes, as a minimum, the following information:" Requirement 2: I suggest modifying the requirement to state: "Each Transmission Operator with ATC Path(s) and with TRM shall only use the components of uncertainty from R1.1 to establish TRM, and shall not include any of the components of Capacity Benefit Margin (CBM). Transmission capacity set aside for reserve sharing agreements can be included in TRM." Requirement 3: I suggest modifying the requirement to state: "Each Transmission Operator with ATC Path(s) and with TRM shall make available its TRMID, and if requested, underlying documentation (if any) used to determine TRM, in the format used by the Transmission Operator, to any of the following who make a written request no more than 30 calendar days after receiving the request."     
IndividualEric MortensonExelon  Yes  In MOD-008-1 the following requirement was removed: R1.2.A A statement to confirm that it shall use assumptions in calculating TRM that are consistent with those assumptions that are used in the Transmission planning process for the time period studied". The NERC ATCWG reached conclusion on the following rule as they were developing the “Transmission Capability Margins and Their Use in ATC Determination” white paper which discusses the reliability margins of TRM and CBM: A Transmission Provider’s ATC/AFC calculations, and associated margins, must be consistent with the Transmission Owners’ and Public Power Entities documented Planning Criteria This rule was incorporated into the “Transmission Capability Margins and Their Use in ATC Determination” white paper dated June 17, 1999 as demonstrated in the following exert: Ø “The methodology used to derive TRM and its components must be documented and consistent with published planning criteria, and must not account for uncertainties already accounted for elsewhere in the ATC determination. A TRM is considered consistent with published planning criteria if the same components that comprise it are also addressed in the planning criteria. The methodology used to determine and apply TRM does not have to involve the same mechanics as the planning process, but the same uncertainties must be considered and any simplifying assumptions explained. It is recognized that ATC determinations are often time constrained and thus will not permit the use of the same mechanics employed in the more rigorous planning process” AFC/ATC calculations must be consistent with each Transmission Owner’s planning criteria in order to maintain reliability. AFC/ATC calculations must not be subject to evaluation scenarios that exceed or are ‘beyond’ the applicable planning criteria. For example, if the most extreme event a Transmission Owner plans for were single contingencies, it would be inconsistent with the applicable planning criteria to evaluate a transmission service request to meet a double contingency test. In this instance, evaluating a transmission service request using double contingency analysis would be in conflict with the planning criteria and would not be compatible with the reliability requirements used to serve native connected load. In an ATC calculation the following components determine the loading on a flowgate for the period of time under evaluation: 1. Base Case Flows (which recognizes the forecasted load connected to the transmission network and planned system topology) 2. Impacts of existing transmission service reservations -- both positive and negative (i.e. counterflow) 3. TRM (consistent with applicable Planning Criteria) 4. CBM (consistent with applicable Planning Criteria) When these four components are applied to a flowgate the result is a calculated AFC. If the resultant AFC is negative, the result indicates that the flowgate is projected to be overloaded because of the preexisting commitments (i.e. the four components listed above). In some cases negative AFC values exist for future years preventing transmission customers from obtaining transmission reservations for these future time periods. The inconsistency between Transmission Provider’s AFC/ATC calculations and the Transmission Owner’s Planning criteria becomes evident when the Transmission Owner internal planning processes does not result in identification of system deficiencies requiring system expansion – even on Flowgate determined by the Transmission Provider to have negative AFC values far into the future. The likely cause of this discrepancy is that the TO is not applying the same scenario, including the same transmission uses (i.e. confirmed reservations), or consistent margins (TRM/CBM) in its internal planning process.      
IndividualMaria NeufeldManitoba Hydro  No preference  Yes Yes  
Group  NERC RTOSDTJim Case, Chair       The Real Time Operation Standards Drafting Team is concerned that the proposed MOD standards do not include any reference to the Planning and Operating Limits mandated by the current FAC, IRO and TOP standards. These standards already include transmission flow limits both in the longer term planning time frame as well as the shorter term operating time frame. The proposed MOD standards seem to be establishing procedures to calculate the commercial boundaries without a direct link to the required reliability boundaries. ============================================================= MOD-001 R6 states that the TTC “use assumptions” no more limiting than those used in planning. The RTO SDT would ask shouldn’t TTC’s be required to be “no less limiting” than the SOLs / IROLs computed for the system? Current NERC standards are not just asset limits, they are also system limits. The current standards require that limits be calculated that recognize both local and wide-area impacts. The RTO SDT believes that by at least linking (if not entirely eliminating) the MOD standards to the current SOLs / IROLs requirements, the Industry would be more correctly linking how the system MUST BE operated to any NAESB business practice. Indeed it would seem that current tariffs are based on the computations used in current planning and operating environments. By using the current SOL / IROL limits the procedural / prescriptive requirement in MOD-001 R9 et al would be unnecessary (i.e. they would revert back to the FAC and IRO requirements) The questions for the ATC SDT: • How do these MOD standards relate to the SOLs / IROLs • Why should these ATC/TTC limits be decoupled from the SOLs / IROLs • Shouldn’t the long-term SOL / IROL limits computed in Planning be the TTC for the system (or at least the basis for the TTC) • Shouldn’t the short-term SOL / IROL be the basis for the ATC for the system? MOD-008 computes margins. By coordinating the MOD standards with the SOL / IROL standards, the only Business (not NERC) requirement may be to define the options on how the TSP could couple the various SOL / IROL values that it obtains from its RCs and TOPs. MOD-028 By using SOLs / IROLs there would be no need to get into ATC / AFC “methodologies”. Indeed standards that include “alternatives” are not defining a single “standard approach”. But by using specific planning and operating limits the methodologies become irrelevant. The “limit” becomes explicit and well-defined. Any margins or variations about those limits would then be obvious and transparent. What is most important is respecting the reliability-based limits and not how the commercial value is computed. If this idea of using SOLs / IROLs as the limit(s) or at least the basis for those commercial limits, then the TSP becomes a coordinator of which values to use for the commercial periods. The TSP would not be the computer of those limits. Thus MOD-028 could become a business practice for posting – rather then a standard for computations.
Group  NPCC Regional Standards CommitteeGuy V. ZitoYes  None  Yes The language in the Proposed Effective Date should be modified to be consistent with the other standards
Group  FirstEnergyDoug HohlbaughNoWithin many RTO areas it is the TSP who maintains the TRM Methodology and assures its appropriate implementation while calculating ATC or AFC. This is the case in a large portion of the continent and a standard should not be written in a way that would knowingly require an assignment delegation for a large number of potential responsible entities. Assigning the applicability in this standard to the TSP would work for non-market areas of the continent since in those areas the TOP most likely serves as its own TSP. R2 – This requirement states "Each Transmission Operator shall only use the components of uncertainty from R1.1 to establish TRM, and shall not include any of the components of Capacity Benefit Margin (CBM). Transmission capacity set aside for reserve sharing agreements can be included in TRM." We recommend replacing "only use" with "include" since "only use" presumes that the list of uncertainties stated in the standard are all inclusive of all factors that a TOP/TSP may want to address in TRM. The requirement explicitly states that CBM should not be included in TRM, so making this change should not create an opportunity for double dipping on CBM. YesFE supports the SDT's adjustment of VRFs such that no VRF within the ATC standards exceeds a "Lower" rating. We concur with the team's reasoning and rationale provided in response to ballot comments in making this change.NoThe Severe VSL stated for requirement R2 does not seem appropriate if a TOP/TSP included elements of uncertainty that were outside of those items explicitly stated in R1 so long as all of the items in R1 are covered AND that CBM is not included in its TRM. See proposed change above for R2. FirstEnergy appreciates the Standard Drafting Team's decision to move to a formal comment period based on the prior initial ballot feedback. We commend the team for moving quickly to respond to the ballot comments and providing the industry a revised set of standards to review and comment. Regarding the revision to the Effective Date, while FirstEnergy agrees that there is a need to ensure that the standard is implemented consistently across the entire continent we are concerned with the Effective Date being subject to approval of ALL regulatory authorities. We believe an appropriate Implementation Plan should reflect a period of time beyond the NERC Board of Trustee approval date that would reflect when the requirements are considered mandatory and enforceable. The timeline should allow sufficient time for regulatory authority reviews, with the intent of sanctions also being enforced in conjunction with the conclusion of the implementation period. However, a delay from a given regulatory agency should not impact when the requirements are considered mandatory and enforceable for the bulk electric system.
IndividualThad NessAEP  NoThe Transmission Service Provider is the applicable entity.      
Group  Public Service Commission of South CarolinaPhil RileyNo preference  Yes Yes  
IndividualPatrick BrownPJM  Yes  Although the SDT had the appropriate Team to establish a default percentage for TRM, the FERC deadline did not allow enough time to complete this portion of the requirement. Since TRM is a reliability margin, PJM encourages the Team to provide what ever input it currently has in a ‘parking lot’ for a possible future Team to undertake the development activity. There should be a default percentage to be used without requiring specific documentation, work papers and load flow cases if a straight percentage such as 5% is used. Additional information would be required only if a greater percentage is used. 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. 
IndividualGreg RowlandDuke Energy Corporation  Yes   Yes Yes Implementation Plan – Since R2 and M2 link the TRM calculation methodology with the CBM methodology in MOD-004, implementation dates for these standards should be aligned. Since R2 and M2 link the TRM calculation methodology with the CBM methodology in MOD-004, the Standards Drafting Team must avoid creating a duplicate requirement the CBM standard, which could subject entities to multiple penalties for the same violation.
Group  Bonneville PowerDenise KoehnYes  BPA does not believe any are incorrect.Yes Yes BPA respectfully submits the following observations and suggestions: a. The sixth component of uncertainty listed in R1.1 should be expanded as follows: - Variations in generation dispatch (including forced or unplanned outages, maintenance outages, and location of future generation). b. To comply with FERC Order 890 transparency requirements, R1.5 should not be removed (e.g. “If TRM is not used, a statement of that practice.”) – BPA believes a Transmission Operator should be required to provide a robust justification as to why it is not using TRM in it’s ATC or AFC calculations. c. A new R6 should be added that clearly states the timeframe in which TRM is to be used (i.e. within the hour). d. The Time Horizons listed for all requirements should include the “Long-term Planning” Horizon, as TRM is to be calculated beyond the seasonal window. e. 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.
IndividualGreg Ward / Darryl CurtisOncor Electric Delivery  No preference 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 2.
IndividualRichard KafkaPepco Holdings, Inc  Yes  PHI supports the comments of PJM and will not submit duplicate comments     
IndividualEarl FairGainesville Regional Utilities  NoI would suggest the TSP and let that entity negotiate, via mutual agreement, to delegate these task.R2: Why limit what items can be considered in developing TRM? What reliability purpose could it possibly serve? R1,3,4 & 5 are OK as presented.Yes Yes None at this time.
Group  ISO RTO Council/Standards Review Committee (SRC)Charles YeungYes   YesThe MOD standards assess the correct amount of reliability risk in areas that do not affect reliability. The IRC supports the position that no requirement from this set of ATC standards should have an assigned Risk Factor exceeding “Lower”. A Lower Risk Factor requirement is administrative in nature and (a) 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; or (b) is a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or restorative conditions anticipated by the preparations, be expected to affect the electrical state or capability of the bulk power system, or the ability to effectively monitor, control, or restore 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 the IRC has a concern regarding the possibility of multiple violations resulting from a single event. The IRC requests that the potential for double counting of violations for a single event be eliminated.Although the SDT had the appropriate Team to establish a default percentage for TRM, the FERC deadline did not allow enough time to complete this portion of the requirement. Since TRM is a reliability margin, the IRC encourages the Team to provide what ever input it currently has in a 'parking lot' for a possible future Team to undertake the development activity. There should be a default percentage to be used without requiring specific documentation, work papers and load flow cases if a straight percentage such as 5% is used. Additional information would be required only if a greater percentage is used.
Group  MRO NERC Standards Review SubcommitteeTom MielnikYes  1. The MRO believes that M1 should be revised to delete the words "all" from the phrase "all specified information…". This use of "all" seem to be unnecessary and may result in over-the-top auditing. 2. The MRO commends the SDT on deleting R1.2.A and R1.5. The MRO believes that these former requirements were unnecessary and not reliability related and that the changes are significant improvements to the standard. 3. The MRO is asking for clarification in R1.1 on "Reserve sharing requirements". The MRO is assuming that this is not non-operating reserves such as planning reserves. 4. R1.1, bullet 7 reads: Short-term System Operator response (Operating Reserve actions not exceeding a 59-minute window). The "59-minute window" conflicts with BAL-002. Under BAL-002, operating reserves can be supplied for up to 105 minutes (R4.2 15 minutes for the disturbance plus R6.2 90 minutes). We suggest the following wording instead: "(Operating Reserve actions not exceeding the operating reserve sharing deployment period)". YesThe MRO commends the SDT on revising the VRFs to Lower. We believe the revised VRFs are in-line with the NERC definitions of the VRF levels.Yes 1. The MRO commends the SDT in making significant changes to this standard and reissuing it for comment. The MRO believes the eventual standard that is approved will serve the industry and customers better as a result. 2. The MRO believes that the first time you use an abbreviation or acronym, you must spell out the full term followed by the abbreviation or acronym in brackets. Subsequent use of the term is then made by its abbreviation or acronym.
IndividualRon FalsettiOntario IESO  Yes  NoneNoThe VRF for R4 should be a Medium. R4 stipulates that the TOP establish a TRM. Given that TRM is that portion of the ATC reserved to cover for uncertainties that can affect transmission reliability, failure to establish this value could result in the TOP facing unreliable operations due to the TSP offering and committing this value as a transmission service to transmission users. The end result could have a direct impact on the control and reliability of the BES.Yes The language in the Proposed Effective Date should be modified to be consistent with the other standards
IndividualAlessia DawesHydro One Networks  Yes  noneYes Yes Language in the Proposed Effective Date should be modified to be consistent with the other standards, e.g. MOD-001-1
Group  Entergy Services Inc.Narinder K. SainiYes  R2- Entergy recommends deleting the phrase "and shall not include any of the components of Capacity Benefit Margin (CBM).Yes Yes  
IndividualJohn HarmonThe Midwest ISO  Yes  R1.1 – Please clarify the uncertainty components below: o Allowances for simultaneous path interactions (how is it different from loop flow above?) o Short-term System Operator response (Does this exclude reserve sharing requirements?). R2 – This requirement as it is written doesn’t allow the Transmission Operators to include any other uncertainties other than from R1.1. If R1.1 is not trying to list the complete set of uncertainties, we recommend to revise R2 to “Each Transmission Operator shall not include any of the components of Capacity Benefit Margin (CBM). …” Yes Yes  
Group  Southwest Power PoolKevin BatesYes   Yes    
IndividualJason ShaverAmerican Transmission Company  Yes We agree that the Transmission Operator is the correct entity but are concerned with the inserted exlcusion. Why did the SDT insert the exclusion in this draft of the Standard? (No previous drafts contained this exclusion.) How would a TOP go about notifing NERC that MOD-008 is not applicabile to them? How would NERC or the Regions know if something changed and the TOP is now performing TRM? When would this standard apply to a TOP that does not currenlty perform a TRM? An alternate approach is to have TOPs that do not perform TRMs, cerify yearly that they do not peform TRMs and therefore satisfy MOD-008-1. Modification Requirement 1: Each TOP shall prepare and keep current a Transmission Reliability Margin Implementation Document (TRMID) that includes the following information: The phrase "as a minimum" is not needed because the TOP has to include all sub-requirement in order to meet requirement 1. Any information above that which is listed is outside of NERC's audit. Modifications to Requirement 4: Each TOP shall establish TRM values in accordance with the TRMID at least once every 13 months. Modification to Requirement 5: The TOP shall provide the TRM values to its TSP(s) and TP(s) no more than seven calendar days after a TRM value is initially established or subsequently changed. The phrase "using TRM" conflicts with Requirements 1 - 3. In addition we believe the deletion aligns with our comment on the applicability section. M1 should be revised to delete the words "all" from the phrase "all specified information…" to avoid being overly inclusive. Yes Yes The first time that each abbreviation or acronym is introduced, the full terminology should be stated followed by the abbreviation or acronym in brackets (i.e. ATC). The Proposed Effective Date for MOD-008-1 is different then that written for MOD-001-1. Why the difference in the Effective Date? We do not believe that the SDT has to provide a definition of TRMID. Requirement 1 outlines the specifics of TRMID and we find the definition unnecessary. The SDT should explain why this definition is necessary and what if anything is it including that the requirement does not already contain.
IndividualAlice DruffelXcel Energy  NoWe feel that the applicability should apply to the TSP, recognizing that the TSP will require input from the TOP. To further explain, the ATC/AFC methodology is primarily a mechanism for the TSP to sell/provide transmission service in a manner that ensures the transmission system is secure. A TOP however will utilize SOLs and IROLs in the operations of the transmission system, and do not necessarily have to be the same as the ATC/AFC components. As an example, in the selling of service, TRM will not be sold so the limit =TTC-TRM. However the TOP may operate into the TRM during real-time operations and not hold this margin, but honor the true system limit. As another example, there are interdependent flowgates where the ATC components will be based on the most conservative combination, but the system will be operated to minimize restrictions. This may result in a sliding operating limit for the TOP based on actual conditions, while a TSP has to use the most conservative limits for ATC/AFC.R1.1, bullet 7 reads: Short-term System Operator response (Operating Reserve actions not exceeding a 59-minute window). The "59-minute window" seems arbitrary and potentially conflicting. We suggest the following wording instead: "(Operating Reserve actions not exceeding the reserve sharing deployment period)". If the drafting team does not like the suggestion, then please clarify what is the basis for an odd # of minutes, instead of using more common 1/4 or full hour incriments? Under BAL-002, operating reserves can be supplied for up to 105 minutes (15 minutes for the disturbance plus 90 minutes). Yes Yes  
IndividualRex McDanielTexas-New Mexico Power company  No preference 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 should not apply to ERCOT for the reason expressed in question 2.
Group  PPL Supply GroupAnnette Bannon  R3. PPL suggests that the Purchasing/Selling Entities should be included in the listing of entities under Requirement R3.     
IndividualTony KroskeyBrazos Electric Power Cooperative, Inc.  Yes The TOP is the responsible entity however, if the TOP operates in a single-control area region the establishment and applicability of TRM may have no reliabilty benefits.      Brazos Electric believes that for a TOP operating in a single-control area region like ERCOT that the establishment of TRM may have no reliability benefits. The Applicability Section 4.1 for MOD-008 as written in this draft states "Transmission Operators that maintain TRM" could possibly be interpreted that this applies only to those TOPs who have a need to establish TRM because of the region it operates in. Otherwise in R1 it is reconmmended that an "if applicable" clause be inserted to address this issue.
Group  Electric Service DeliveryReza Ebrahimian        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.
IndividualAaron StaleyOrlando Utilities Commission  No preference  Yes Yes Requirements 1, 3, 4 and 5 are great exactly as they are. They are a good balance of standardization, disclosure and recognition that different parts of the transmission system function differently and are most sensitive to different factors. For Requirement #2, what is the reliability purpose for limiting the items that an entity can consider when establishing TRM?
IndividualRick GonzalesNew York Independent System Operator  Yes  The NYISO has previously commented that R4 would require TRM to be recalculated more frequently than necessary for Transmission Operators whose TRM assumptions do not change frequently. Under the NYISO system, TRM values are stable over time and often do not change for periods longer than 13 months. The NYISO therefore renews its request that the SDT modify R4 to specify that TRM need not be re-established (or re-calculated) every 13 months to the extent that none of the underlying TRM inputs have changed. The SDT has previously revised R8 under MOD-001 in the same manner and there is every reason to make the same change to R4 under MOD-008. Yes