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 Individual or group.NameOrganizationGroup NameLead ContactQuestion 1Question 1 CommentsQuestion 2Question 3Question 4Question 4 CommentsQuestion 5Question 5 CommentsQuestion 6 Comments
Individual  American Public Power AssociationAllen MosherNo - one or more definitions needs revision - see comments“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-28-1 R10, for example, reads: “counterflowsF are adjustments to firm ATC as determined by the Transmission Service Provider and specified in the 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: “PostbacksF 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, capitalize existing transmission commitments in the definition of ATC. Transmission Service ProviderR3.3 - seems awkward for tranfer capability to not be a defined term when TTC and ATC are defined; at minimum, edit to read transfer or Flowgate capability. R3.6 - clarify that "outages" are transmission outages, generator outages or both. R8.1 - why hardwire 80 hours per calendar year during which calculations are not required to be performed? Should this be a compliance Measure?Yes Yes Excellent work - my thanks to the SDT members.
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 Available Transfer Capability Working Group (ATCWG) Dough BaileyYes - definitions are acceptable as revised No Preference Yes    
IndividualJohn HarmonThe Midwest ISO  Yes - definitions are acceptable as revised Transmission Service ProviderR3.3 – last line should read: …calculating ATC or AFC. R3.4 – last line should read: …calculating ATC or AFC. R3.5 – Each bullet should read: …allocate ATC or AFC… R6 and R7 – The term ‘assumptions’ is not specific enough for entities to prepare for compliance. The Midwest ISO requests the standard to list specific assumptions within the scope and what defines ‘more limiting’ for each of them. For example, is load assumption within the scope? If yes, what load assumption is more limiting? If it is not possible, the Midwest ISO believes that this topic from Order 890 should be left out from any standard and left to FERC to address issues on a case by case basis. R9 – Please expand/clarify the intentions of the 4th bullet. What specific aggregated firm capacity is being referenced? Capacity in ETC for each flowgate as specified by reservations? An example would be very beneficial. R9 – The 13th bullet should read: ..(TRM), and TTC or TFC for all….. M6 – Include reference for TFC, should read: …used for TTC, or TFC, and Operations Planning…. Yes NoThe VSLs for R8 of MOD-001 are inconsistent to the VSLs stated for R10 of MOD-030 although each is related to comparable requirements regarding the frequency of recalculations. If the suggestion of deletion of R10 in MOD-030 is accepted the inconsistency will be addressed. Otherwise, the team should align these VSLs consistently. 
IndividualJohn DalessiTransmission Agency of Northern California  Yes - definitions are acceptable as revised No Preference Yes Yes R.9 lists many data elements that another entity can request and a TSP is obligated to provide. Not all TSPs have or use this data themselves, and R.9 should be clarified to state that the TSP is not obigated to provide data it does not have. Perhaps this is implied in R9.1, but if so it should be stated more clearly. Also the first sentence of R.9 is ambiguous - I assume the requested data is for use in the requestor's ATC or AFC calculations, but it could also be read that the data is used in the ATC/AFC calcualation of the TSP receiving the request.
Group  WECC Market Interface Committee / Sub Commtt / ATC Task ForceW. Shannon Black Yes - definitions are acceptable as revised Transmission Service ProviderMOD-01, R9. Could the NERC Team please clarify "which" Load Forecast it is requesting? Hourly? Daily? For what affected area? MOD-01, R9. Could the NERC Team please clarify that Block/Dispatch Order and Participation Factors do not call for the submission of specific schedules; rather, these defintions only call for dispatch rules from which approximations can be made. Yes Yes  
Group  Southwest Power PoolKevin BatesYes - definitions are acceptable as revised   Yes   R3.6.3. How outages (including those outages from other Transmission Service Providers that are unrecognized) are processed. Define "unrecognized." Does this also refer to outages that are not used because the elements are well outside the TSP’s model and therefore do not impact calculations? _________________________________________________________________________________________________ R9. Within thirty calendar days of receiving a request by any Transmission Service Provider, Planning Coordinator, Reliability Coordinator, or Transmission Operator for data from the list below for use in ATC or AFC calculations, each Transmission Service Provider receiving said request shall begin to make the requested data available to the requestor, subject to the conditions specified in R9.1 and R9.2: The concern of R9 is numerous requests that could create an unnecessary burden for TSPs fulfilling said requests. SPP feels a justification should be provided with requests to promote comunication between requestor and TSP so desired result is obtained.
IndividualMaria NeufeldManitoba Hydro  Yes - definitions are acceptable as revised No Preference Yes Yes  
IndividualJack Cashin/Barry GreenEPSA  Yes - definitions are acceptable as revised No PreferenceR6/7. I believe the wording of this requirement in the previous draft was superior. In the revised language, deletion of the word "consistent" allows for discontinuities in the ATC calculations. For example, if the assumptions used in "planning of operations" in the period beyond one month are different than for those in the current month, this could create discontinuities where the calculations adopt different assumptions. In addition, the current language has broken the explicit link between planning studies and operations studies.  no comment NO COMMENTWe offer two additional comments. First, with respect to the purpose of this standard, we believe the purpose of the previous draft was more appropriate. The previous draft stated that consistency in the calculation of ATC and appropriate documentation were part of the purpose of this standard. We believe those are important purposes and should be included. Secondly, requirement 3.2 dealing with counterflows is insufficient in the current draft. We accept that consistency in the use of counterflows on all interfaces would not be appropriate. Indeed it is likely that even within a single system, it is likely appropriate that the counterflows on some interfaces be treated differently than others based on historical usage of the interface. However, to create a standard that requires only an identification of the methodology and a statement of the rationale, with no guidance on appropriate methodologies or acceptable rationales is not sufficiently enforceable and amounts to a fill-in-the-blank standard.
Group  Public Service Commission of South CarolinaPhil RileyYes - definitions are acceptable as revised No Preference Yes Yes  
Group  ISO RTO Council/Standards Review Committee (SRC)Charles YoungYes - definitions are acceptable as revised  Requirement 2 •While the IRC understands that the SDT believes that the requirements need to address the amount of ATC or AFC data calculated and the frequency of calculation associated with them, these requirements should be business practices and should be considered NAESB scope and eliminated from the MOD Standards. The MODs can still address FERC orders and be reliability based without the MOD-001 R2 (amount of ATC or AFC) and R8 (frequency ATC recalculation) and MOD-030 R10 (frequency AFC recalculation) requirements. The violation severity levels for these draft standards now have a graded implementation. The possibility of multiple violations resulting from a single event still remains. The IRC requests that double counting of violations for a single event be eliminated. A single event shall not result in multiple violations. This language should be added to the standard as a new item 6 to section A of MOD-001. Requirement 3 •R3.2.1 - The IRC understands the SDT’s reasons for using “Confirmed” reservations in accordance with the FERC regulations. However, reservations that are in “Accepted”, as well as, “Confirmed” status should be included. Once service is “Accepted” by a TSP it cannot be retracted. Using reservations that are in “Accepted” and “Confirmed” status should also be included in MOD-030 R6.3, R6.4, R7.1, and R7.2. This does not prevent the TSP from decrementing for accepted and confirmed TSRs. We understand that some TSPs maintain two sets of ATCs. One set is maintained internally and accounts for accepted and confirmed TSRs. The other set of ATC values is maintained externally and only accounts for confirmed TSRs. It is important for TSPs who maintain two sets of ATC values to post the “internal” ATC values to provide greater transparency and give customers a more accurate picture of capability available to new requests. •R3.6 - For R3.6 in MOD 001 requires outages to be included in the daily and monthly calculations. R5.2 in MOD 30 requires outages to be included in the hourly calculations. A single requirement should be placed in MOD 1 and applied consistently across MODS 28, 29 and 30. Requirement 8 •If R8 is not moved to NAESB Business Practices then revise R8.1 and the VSL to align the requirement and NAESB practice which allows OASIS to be down 2% of the time over a year. Modify the 80 hour per year allowable outage requirement to 175 hours per year (8760 hrs/year x 0.02= 175 hours). This VSL does not become a possible sanction until the accumulated amount of hours missed exceeds 175 hours. The 175 hours is for planned, system IT outages. Unplanned, system IT outages should not be included in this total. 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.NoERC 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 double counting of violations for a single event be eliminated. The IRC recommends that the SDT add a new item 6 to section A of MOD-001 that states "A single event shall not result in multiple violations". A review of MOD-001 R2 and R8 should be performed for determination of multiple violations resulting from one event. The IRC applauds the efforts of the NERC Standards Drafting Team (SDT) in providing a set of MOD standards for formal comment that include many of the Industry's comments from the Ballot. However, there are several standards which still require modification. The MOD standards extend into areas that should be covered and addressed by NAESB Business Practices (as defined in MOD-001 Definitions). The frequency of postings and frequency of AFC/ATC calculations should be NAESB Business Practices, and not included in the NERC Standards as reliability based requirements (see specific details for MOD-001 R2 and R7). Non-firm should be removed from this reliability standard.
IndividualH. Steven MyersERCOT ISO  Yes - definitions are acceptable as revised Transmission Service ProviderRequirement 1: I suggest modifying the requirement to state: "Each Transmission Service Provider with ATC Path(s) shall select one ATC methodology for calculating ATC (Area Interchange methodology, Rated System Path methodology)or AFC (Flow gate methodology) for each ATC Path per time period identified in R2 for those facilities within its Transmission Service Provider area." Comment: The TOP is to operate its transmission operating area in a reliable manner and ensure SOLs are determined. ATC is a transmission service market concept, not a reliability function. In areas where there is a transmission service market in operation, there is some reliability value to having a representative ATC in play to ensure proper planning is conducted, but reliability is ensured by adherance to the SOLs of the system, not by adherance to ATC. Requirement 3: I suggest modifying the requirement to state: "Each Transmission Service Provider with ATC Path(s) shall prepare and keep current an Available Transfer Capability Implementation Document (ATCID) that includes, at a minimum, the following information:" Requirement 4: I suggest modifying the requirement to state: "The Transmission Service Provider with ATC Path(s) shall notify the following entities (via electronic mail) before implementing a new or revised ATCID." Requirement 5: I suggest modifying the requirement to state: "The Transmission Service Provider with ATC Path(s) shall make available the current ATCID to all of the entities specified in R4." Requirement 6: I suggest modifying the requirement to state: "When calculating TTC or TFC, the Transmission Service Provider with ATC Path(s) shall use assumptions no more limiting than the estimated SOLs used in planning of operations for the corresponding time period studied." Requirement 7: I suggest modifying the requirement to read: "When calculating ATC or AFC, the Transmission Service Provider with ATC Path(s) shall use assumptions no more limiting than the estimated SOLs used in planning of operations for the corresponding time period studied." Requirement 8: I suggest modifying the requirement to state: "Within 30 calendar days of receiving a request by any Transmission Service Provider, Planning Coordinator, or Reliability Coordinator for data from the list below for use in ATC or AFC calculations, each Transmission Service Provider with ATC Path(s) receiving said request shall begin to make the requested data available to the requestor, subject to the conditions specified in R9.1 and R9.2." Requirement 9.1: I suggest modifying the sub-requirement to state: "The Transmission Service Provider with ATC Path(s) shall make its own current data available, in the format maintained by the Transmission Service Provider, for up to 13 months in the future (subject to confidentiality and security requirements)." Requirement 9.2: I suggest modifying the sub-requirement to state: "This data shall be made available by the Transmission Service Provider with ATC Path(s) on the schedule specified by the requestor (but no more frequently than once per hour, unless mutually agreed to by the requestor and the provider)."     I suggest modifying the Applicability section to state: 4.1 Transmission Service Provider with ATC Path(s) 4.2 Transmission Oerator with ATC Path(s) Comment: It is unclear how failing to meet the requirements of MOD-001 affects grid reliability. This should be a commercial standard or a business practice rather than a reliability standard requirement. Severity Levels: Violation of timeing requirements should not constitute a severe violation. A severe violation is the failure to attempt to perform the task at all. A high violation could be a long failure to perform, such as >96 hours with NO attempted corrective action. All other failures in timing should be lower violation severity.
IndividualAaron StaleyOrlando Utilities Commission  Yes - definitions are acceptable as revised Transmission Service Provider Yes Yes Overall Question: As written currently, the standard appears to set requirements for calculating TTC/TFC/ATC/AFC etc, but does not require an entity to perform the calculation. For example, R1 and R6 apply to the TOP, but as written if the TOP doesn't calculate ATC/AFC/TTC/TFC then nothing in the requirements seems to obligate them to do so. This also seems to be true of the requirements that apply to a TSP. Is this a correct reading of the requirements? Requirement 6: If the drafting team changes the responsible entity in Requirement 1, will they also change this one? Requirement 6 & 7: What if there is not “planning of operations” activity for the corresponding time period? For example while month 11 may have an ATC study done, it may not have a corresponding “planning of operations” activity. Requirement 6 & 7: Could you provide some examples of what you mean by “assumptions”. Requirement 6 & 7: What is the reliability purpose of these requirements, specifically what is the reliability purpose of setting a maximum threshold on how limiting an assumption can be?
Group  WECC Market Interface Committee ATC Task ForceW. Shannon BlackYes - definitions are acceptable as revised Transmission Service ProviderMod-001, R9. Could the NERC Team please clarify "which" Load Forecast it is requesting? Hourly? Daily? For what affected area? MOD-001, R9. Could the NERC Team please clarify that Block/Dispatch Order and Participation Factors do not call for the submission of specific schedules; rather, these definitions only call for dispatch rules from which approximations can be made.Yes Yes  
IndividualPatrick BrownPJM  Yes - definitions are acceptable as revised Transmission OperatorRequirement 2 • While PJM understands that the SDT believes that the requirements need to address the amount of ATC or AFC data calculated and the frequency of calculation associated with them, these requirements should be business practices and should be considered NAESB scope and eliminated from the MOD Standards. The MODs can still address FERC orders and be reliability based without the MOD-001 R2 (amount of ATC or AFC) and R8 (frequency ATC recalculation) and MOD-030 R10 (frequency AFC recalculation) requirements. The violation severity levels for these draft standards now have a graded implementation. The possibility of multiple violations resulting from a single event still remains. PJM requests that double counting of violations for a single event be eliminated. A single event shall not result in multiple violations. This language should be added to the standard as a new item 6 to section A of MOD-001. Requirement 3 • R3.2.1 - PJM understands the SDT’s reasons for using “Confirmed” reservations in accordance with the FERC regulations. However, reservations that are in “Accepted”, as well as, “Confirmed” status should be included. Once service is “Accepted” by a TSP it cannot be retracted. Using reservations that are in “Accepted” and “Confirmed” status should also be included in MOD-030 R6.3, R6.4, R7.1, and R7.2. This does not prevent the TP from decrementing for accepted and confirmed TSRs. We understand that some TPs maintain two sets of ATCs. One set is maintained internally and accounts for accepted and confirmed TSRs. The other set of ATC values is maintained externally and only accounts for confirmed TSRs. It is important for TPs who maintain two sets of ATC values to post the “internal” ATC values to provide greater transparency and give customers a more accurate picture of capability available to new requests. • R3.6 - For R3.6 in MOD 001 requires outages to be included in the daily and monthly calculations. R5.2 in MOD 30 requires outages to be included in the hourly calculations. A single requirement should be placed in MOD 1 and applied consistently across MODS 28, 29 and 30. Requirement 8 • If R8 is not moved to NAESB Business Practices then revise R8.1 and the VSL to align the requirement and NAESB practice which allows OASIS to be down 2% of the time over a year. Modify the 80 hour per year allowable outage requirement to 175 hours per year (8760 hrs/year x 0.02= 175 hours). This VSL does not become a possible sanction until the accumulated amount of hours missed exceeds 175 hours. The 175 hours is for planned, system IT outages. Unplanned, system IT outages should not be included in this total. 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. Add a new item 6 to section A of MOD-001. For example a review of MOD-001 R2 and R8 and MOD-30 R10 should be performed for determination of multiple violations resulting from one event. Depth of the ATC MOD standards extends beyond the scope of the reliability standards The MOD standards extend into areas that should be covered and addressed by NAESB Business Practices (as defined in MOD-001 Definitions). The frequency of postings and frequency of AFC/ATC calculations should be NAESB Business Practices, and not included in the NERC Standards as reliability based requirements (see specific details for MOD-001 R2 and R7 and MOD-030 R10 in the Specific Comments sections below). Non-firm should be removed from this reliability standard.
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.
IndividualFrank CumptonCalifornia ISO  Yes - definitions are acceptable as revisedPlease see comments given ion last question.      Purpose – The MOD 1 Purpose as presently written does not clearly relate the intent of the associated MOD standards. Purpose statement should be more explicit, i.e. “To require that ATC calculations are performed by TSPs for present (DA and HA) and forecasted system operating conditions on ATC Paths”, using one or more of the 3 ATC calculations options embodied in MOD 28 – 30. Purpose should clearly state “for ATC Paths”, and then clearly define “ATC Paths”. The present MOD 1 CFR definition of “ATC Path” is very open to interpretation, given that “ATC Path” is defined first as a “Posted Path” via a footnote reference to 18 CFR 37.6(b)(1) OR “any OTHER combination of POR and POD for which ATC is calculated”. Posted Path implies a requirement to post the ATC to an OASIS site, and to Market the transmission on the referenced path. The MOD 1 “ATC” definition does refer to the intention that ATC is calculated “for further commercial activity”. Presumption is that the ATC is posted for sale. ATC Path Definition – Clarify that ATC Path definition is applicable ONLY to interties and internal paths between systems where Transmission is sold (for further commercial activity). Clarify if ANY posting requirement is embodied in these standards. Explanation – It is the California ISO’s interpretation is that under MOD 1 and 29, the ISO will be required to calculate and post ATCs for each of its 41 interties. The ISO will use the MOD 29 Rated System Path Methodology to calculate ATCs DA, HA and for future Market timeframes, consistent with practice in the WECC for interchange ratings. However, the ISO will be employing a Flow based Integrated forward Market under its new MRTU Market design to be implemented this Fall. This internal ISO Market will use an Integrated Forward Market in combination with an Full Network Model and LMP pricing to dispatch generation, imports and exports, procure AS and Balancing energy for RT, to optimize use of the grid. This model employs the use of flowgates in the 3000 node FNM. However, the ISO will only be posting ATCs for transmission capability at the 41 ties, consistent with our Market design and interpretation of the definition of ATC Path, provided by these proposed ATC standards. Note; The CAISO operates the combined transmission assets of 11 TOs located within its BAA boundary, as one Transmission system for Market purposes. Is this interpretation consistent with the SDT’s intent? Does the SDT believe that MOD 30 contains any requirement to convert the IFM’s use of flow gates to ATCs, given that these AFCs are not related to ATC Paths, as defined by MOD 1? This would appear to be very impractical and of virtually no Market benefit, as the power flow solution used to dispatch energy in the IFM is only known after the IFM has run, and a power flow solution is reached for each of the thousands of interconnected transmission elements within the BAA for the 3000 nodal bus network. R2 & R8 – Should the actual ATC Calculation timing requirements to relegated to a NAESBY Standard??? Any requirement to calculate and post ATC with any accuracy, should be limited to the Hourly, daily and perhaps weekly values. The requirement to calculate Monthly and yearly ATC values beyond the outage reporting requirements and beyond any reasonable expectation of knowledge of operating conditions, is of minimal use, under and CAISO Market construct. Posting of ATC for timeframes beyond seven days would seem to be very inaccurate, not knowing what the operationally constraints would be to any degree of accuracy (I.e. hydro conditions, forced outages, planned generation and transmission outages, planned maintenance work). R9 - Does this Requirement require that the CAISO release our power flow model to our TO’s, absent a NDA??? See 9th bullet.
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 - definitions are acceptable as revised Transmission Service ProviderNPCC Participating Members have the following comments on specific requirements 1. R3.6.3: This subrequirement is too vague and its addition is not necessary. Subrequirements R3.6.1 and R3.6.2 suffice to hold the TSP responsible for considering the impact of outages in ATC calculation. How the outages are processed has no bearing on the ultimate scenarios (topologies) that the TSP must consider. 2. Also we do not agree with the changes made to R6 and R7. By “no more limiting than” the assumptions used in planning of operations for the same time period, it would imply that the TOP and TSP may use less restrictive (or more liberal) assumptions. The results could be that the TTCs and ATCs are higher than the planned operational parameters, giving rise to potential unreliability. We do not see a problem with the previous wording of “consistent with”, and this should be reinstated Yes NoNPCC Participating Members have the following comments on the VSL: 1. R3: There is a potential overlap between High and Severe. For an ATCID does not include “two or more” of the information items in R3, it could mean does not include all of the information items. This is the same condition as a Severe. We suggest to reword the High VSL to “does not include up to 2 of the information items in R3”; and the Severe VSL to “or its ATCID does not include 3 or more of the information described in R3”, or numbers along that line. 2. We do not agree with the VSLs for R6 and R7 for reasons noted under Q3, above. NPCC Participating Members do not see the role of TOP in this standard. The TOP’s primary responsibility is to operate its transmission operating area in a reliable manner, and determine SOLs and where necessary, transmission transfer capabilities and flowgate capabilities (where applicable). Given the established SOLs, TTCs, TFCs that are determined by the TOP for operational planning, and the TTCs and TFCs determined by other entities such as the RCs, TPs and PCs for wider area and for different time frames, the TSP needs only to calculate ATCs (or AFCs) respecting these established constraints. In doing so, it should be able to select an ATC calculation method to suit its business model and needs, with due consideration to the basis of the TTCs and TFCs that affect its service area. With this in mind, we suggest in our response to Q2, above, that the TSP be the one who selects the ATC method and R1 should be revised accordingly. Note also that it should not be assumed that the TOP area and the TSP area are the same and hence the basis of the TTCs and TFCs that affect the TSP’s area may differ from one part to another. Also we believe the TSP should be the entity to select the method to be used in calculating available transmission transfer capability since it is the entity responsible for processing transmission services, not the TOP. In determining ATCs, the TSP needs to observe SOLs, IROLs and TTCs determined by the TOPs, RCs, TPs and PCs. Keeping the determination of TTCs (TFCs) separate from the determination of ATC, including the latter’s methodology, would be the appropriate approach in moving forward with these MOD standards.
Group  FirstEnergyDoug HohlbaughYes - definitions are acceptable as revised Transmission Service ProviderR1- The selection of a calculation methodology should reside with the party responsible for calculating ATC. As stated in question 2, FE believes that R1, the selection of an ATC methodology, should be applicable to the Transmission Service Provider (TSP) and not the Transmission Operator since within many RTO areas it is the TSP who maintains the ATC methodology documentation and performs the ATC calculations. 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 requirement responsibility to the TSP would also work for non-market areas of the continent where a TO/TOP also serves as its own its own TSP. The TOP should provide a support role in providing data and information that is needed by the TSP to fulfill its responsibilities in calculating ATC. The TSP is overseeing transmission service requests and making determination of the viability of such requests. The TOP has ultimate reliability responsibility in the real-time environment and will manage its system to its system operating limits regardless of the ATC methodology used by its TSP to approve transactions that make use of the transmission operator's system. R3.3 – There appears to be a typo. Replace "of" in the words "transfer of Flowgate capability" with "or" R3.3, R3.4, R3.5 – Suggest the SDT consider replacing the words "transfer or Flowgate capability" with "ATC or AFC" to improve readability. R3.6 – Replace "ATC" with "ATC or AFC". R3.6 (sub-requirements) - The sub-requirements of R3.6 require that outages be included in the daily and monthly calculations, but excludes hourly calculation periods. In MOD-030 (AFC Methodology) requirement R5.2 requires expected transmission and generation outages are included for all applicable time period calculated. It is suggested that a single requirement reside in MOD-001 to cover the hourly, daily and monthly aspects for this intent that would assure consistent application across the MOD-028, MOD-029 and MOD-030 standards. R8 – It is not clear why the frequency for recalculation is only focused on ATC, and does not read "ATC or AFC", similar to the wording used for calculating in R2. In MOD-030 R10 addresses recalculation for the AFC but it seems that with the suggested change in R8 of MOD-001, that R10 of MOD-030 could be eliminated. Additionally they are inconsistent in that R10 does not provide for the 80 hour annual allowance that is stated in R8. 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 VSLs for R8 of MOD-001 are inconsistent to the VSLs stated for R10 of MOD-030 although each are related to comparable requirements regarding the frequency of recalculations. If the above suggestion revising MOD-001 R8 and deletion of R10 in MOD-030 is accepted the inconsistency will be addressed. Otherwise, the team should align these VSLs consistently. 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  Yes - definitions are acceptable as revised Transmission Service Provider     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.
Group  PPL Supply GroupAnnette Bannon   R4. PPL suggests that Purchasing/Selling Entities should be included in the listing of entities under Requirement R4 who have access to the ATCID. R8. PPL suggests that the following changes be made to the calculation time periods: R8.1 should require hourly ATC to be calculated “as close to continuously as possible”. Once per hour is too slow. R8.2 should require daily ATC to be calculated at 15 minute or less intervals. Once per day is too slow. R8.3 should require that Monthly ATC be calculated hourly or at most daily. Once per week is too slow.     PPL suggests that the standard should require that the TSP make available the new ATC as soon as possible.
IndividualGreg RowlandDuke Energy Corporation  No - one or more definitions needs revision - see commentsATC path : Insert the phrase “or Available Flowgate Capability” after the phrase “Available Transfer Capability”.Transmission OperatorR8.1 – The following sentence, “Transmission Service Providers are allowed up to 80 hours per calendar year during which calculations are not required to be performed.” appears somewhat capricious and should be clarified to show the drafting team’s intentions. As presented, it would permit a TP to decide not to calculate hourly ATC for a 3 1/3 day period. Also, R8 does not require recalculation if none of the calculated values identified in the ATC equation have changed. Does R8.1 limit the exemption provided in R8 to 80 hours per year? M7 - insert the phrase “list of contingencies,” before the phrase “loop flow”. Yes Yes  
IndividualGreg Ward / Darryl CurtisOncor Electric Delivery  No - one or more definitions needs revision - see commentsAll 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). No Preference Yes Yes This standard should not apply to ERCOT for the reason expressed in question 1.
Group  Bonneville Power AdministrationDenise KoehnYes - definitions are acceptable as revised Transmission OperatorBPA does not believe any are incorrect.Yes Yes BPA thanks the drafting team for the modifying MOD-001 to not require the conversion of AFC to ATC and agrees with your assessment that there is no reliability need for such conversion. Additionally, BPA respectfully submits the following observations and suggestions: a. The purpose statement of MOD-001 be modified as follows to comply with FERC Order 890-A: Purpose: To ensure the consistent and transparent application and documentation for the variables defined and used in the calculation of Available Transfer Capability (ATC) or Available Flowgate Capability (AFC). b. The Time Horizons listed for all requirements should include the “Long-term Planning” Horizon, as ATC or AFC is to be calculated beyond the seasonal window. c. Balancing Authorities may be appropriately identified as Applicable Entities in this standard and request that the Standards Drafting Team provide an explanation as to why they are not listed.
IndividualAlice DruffelXcel Energy  Yes - definitions are acceptable as revised  1) R3.6.3 Need to strike "that are unrecognized". The term "unrecognized" is problematic and vague. 2) R3.2.2 Please clarify what you mean by "defined accounting". 3) R3.3 There is a typo. Please change "of" to "or".Yes Yes We feel that the applicability of this standard as proposed is problematic. We also do not feel that this problematic nature is resolved by choosing either the TOP or TSP. While it is not a perfect solution, we feel the best option is for the applicability to remain at the regional level. We suggest the following wording: "Regional Reliability Organization, through its members".
IndividualEarl FairGainesville Regional Utilities  Yes - definitions are acceptable as revised Transmission Service ProviderR1: In reading the standard and the definitions, it seems that the std. doesn"t require an entity to calculate TTC/TFC/AFC, but only tells them how it must be done if it is to be done at all. Am I understanding this requirement correctly? R6: If the responsible entity is changed in R1, with it also be changed in this requirement as well? R6&7: If for example a study for month 10 may not have a corresponding "planning of operations" activity, what action is required to fulfill this requriement? R6&7: What is meant by " assumptions"? Can the team provide some GOOD examples? R6&7: I do not see a reliability purpose of these 2 requirements. I do not see how setting a maximum threshold on limiting assumptions can support a reliability interest.Yes Yes None at this time.
IndividualRichard KafkaPepco Holdings, Inc.    Transmission OperatorPHI supports the comments of PJM and will not duplicate the submission of comments     
Group  MRO NERC Standards Review SubcommitteeTom Mielnik No - one or more definitions needs revision - see commentsThe MRO supports the changes to the definitions. However, the MRO believes there is a need to define "counterflows". The MRO suggests that the SDT consider the following definition for Counterflows: "Counterflows are net impacts on a path or flowgate as determined by the Transmission Service Provider and specified in the appropriate implementation document." Capitalize "Existing Transmission Commitments" in the Available Transfer capability definition, since it is a defined term. Transmission Service Provider1. The MRO agrees with the changes made to replace "ATC" with "ATC or AFC" in the standards. However, the MRO believes this change should be made to R3.6 should be revised this way as well to say "A description of how outages are considered in ATC or AFC calculations, including:". 2. The MRO continues to believe that R4 should be revised to match M4 "The Transmission Service Provider shall provide evidence (such as dated electronic mail messages) that it has notified the entities specified in R4 before a new or revised ATCID was implemented. (R4)" The MRO does not see the reliability need to specify the media via how the Transmission Service Provider notifies the following entities. However, if the issue is that the SDT believes that there must be a record of the notification, the MRO suggests that the words "in writing" be used allowing the Transmission Service Provider to determine the media of notification. 3. The MRO believes that R8 should also be revised to refer to "ATC or AFC" rather than just "ATC". 4. The MRO believes that R5 should be revised to delete the words "all of". The phrase "all of" seems to be unnecessary and may result in over-the-top auditing. 5. The MRO believes that the changes made to R6 are a significant improvement to the standard and commends the SDT on taking this more reasonable approach to consistency, that is "no more limiting than those used in planning of operations." 6. The MRO believes that R9 should be revised to delete the words "any" from "Within thirty calendar days of receiving a request by any Transmission Service Provider…". R9 should be revised to delete the words "all" from "Unit commitments and order of dispatch, to include all designated network resources…". R9 should be revised to delete the words "Any" from the phrase "Any firm and non-firm adjustments…". R9 should be revised to delete the words "Any" from the phrase "Any other services that that impact …..". R9 should be revised to delete the word "all" from "Values of CBM and TRM and TTC for all ATC [paths or Flowgates." R9 should be revised to delete "any" from the phrase "any Flowgates considered by the Transmission Service Provider receiving the request…" R9 should be revised to delete the word "all" from the phrase "Values of TTC and ATC for all ATC Paths for those…". These uses of "any" and "all" seem to be unnecessary and may result in over-the-top auditing. 7. The MRO believes comparable changes should be made to deleting "all" and "any" in the Measures, the Compliance section, and the Violations Severity Levels to match the changes to R9. 8. R3.6.3 Need to strike "that are unrecognized". The term "unrecognized" is problematic and vague. 9. R3.2.2 Alternate language for the statement "a rationale for the defined accounting" A suggestion to use counterflow process instead. 10. R3.3 There is a typo. Please change "of" to "or". YesThe MRO commends the SDT in the changes made to VRFs to Lower. The MRO agrees that these changes puts the VRFs more in line with the NERC's 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. ex: "Each Transmission Operator shall select one Available Transfer Capability (ATC) methodology2 for calculating ATC (Area Interchange methodology, Rated System Path methodology) or Available Flowgate Capacity (AFC) (Flowgate methodology) for each ATC Path per time period identified in R2 for those Facilities within its Transmission Operator Area." R3.3 – last line should read: …calculating ATC or AFC. R3.4 – last line should read: …calculating ATC or AFC. R3.5 – Each bullet should read: …allocate ATC or AFC… R6 and R7 – Overall, both requirements as written are unclear. The MRO asks that the standards drafting team specify what assumptions are referenced or else delete these requirements. Also the MRO objects the requirement to use assumptions that are no more limiting in that such a requirement would result in potentionally onorous calcualations to determine assumtions that meet this limitation. The MRO notes that these requirements are covered by FERC order #890 anyway. R9 – Please expand/clarify the intentions of the 4th bullet. What specific aggregated firm capacity is being referenced? Capacity in ETC for each flowgate as specified by reservations? An example would be very beneficial. R9 – The 13th bullet should read: "Values of Capacity Benefit Margin (CBM) and Transmission Reliability Margin (TRM),and TTC for all ATC Paths or (TFC) for Flowgates." M6 – Include reference for TFC, should read: "Alternatively the Transmission Operator may demonstrate that the same load flow cases are used for both TTC or TFC…"
Group  Entergy Services IncNarinder K. SainiYes - definitions are acceptable as revisedRevised definitions are acceptableTransmission OperatorR3.3 - Replace "---transfer of Flowgate capability." by "---transfer or Flowgate capability." R3.6.3 - Entergy is not sure what the parenthetical is implying, specifically the phrase, "that are unrecognized." In addition, Entergy proposes that rather than processing of outages, it should refer to modeling of outages in ATC calculations, therfore, replace "processed" by "modeled". R6 and R7 - The phrase "planning of operations" may be better understood if the term "reliability" was inserted at the beginning. We assume that the SDT is trying to tie the reliability planning studies/activities to the ATC calculations. Similar terms are used in MOD-030. (This also raises the question of why it is in MOD-030 and not MOD-028 and MOD-029.) If all instances can use the same phrase, we think the standards would benefit from the standardization. R8.1 needs to be worded as requirement rather than giving allowance/exemption from the requirement for 80 hours (approx 1% of 8760 hours) in a calendar year. Entergy recommends the language "Hourly values, once per hour at least 99% of hours every calendar year." R9 - This requirement is for sharing the data by TSP with others who need it for calculation of their ATCs. This requirement is not to replace the requirement of Order 889 37.6(b) (2)(ii) "On request, the Responsible Party must make all data used to calculate ATC and TTC for any constrained posted paths publicly available (including the limiting element(s) and the cause of the limit (e.g., thermal, voltage, stability)) in electronic form within one week of the posting. The information is required to be provided only in the electronic format in which it was created, along with any necessary decoding instructions, at a cost limited to the cost of reproducing the material." If it can be emphasized this fact, it will greatly clarify some confusion that some stakeholders are having regarding data sharing. Yes Yes The effective date info provided in the standards posted indicate that all 5 standards should become effective together. It seems that MOD-004 should also be a part of the set becoming effective. CBM is referenced in the posted standards. R3.2.2.2 The term "accounting" implies bookkeeping and dollars - obviously not something that should be included in a reliability standard. We suggest adding some clarification to this requirement to ensure the intent is clear to all audiences: "A rationale stating how counterflows are accounted for." R3.3 Change "of" to "or" in added phrase. M7 - We do not feel that it is prudent to use switching operating guides and load shedding, etc to sell transmission service. To even suggest these in M7 seems misguided and in conflict with the current draft of the TPL standards. R8.2 and 8.3 need a grace period similar to R8.1 to account for unforeseen system emergencies where the selling of ATC is suspended or technology issues.
IndividualRon FalsettiOntario IESO  Yes - definitions are acceptable as revised Transmission Service ProviderWe have the following comments on specific requirements: 1. R3.6.3: This subrequirement is too vague and its addition is not necessary. Subrequirements R3.6.1 and R3.6.2 suffice to hold the TSP responsible for considering the impact of outages in ATC calculation. How the outages are processed has no bearing on the ultimate scenarios (topologies) that the TSP must consider. 2. We do not agree with the changes made to R6 and R7. By “no more limiting than” the assumptions used in planning of operations for the same time period, it would imply that the TOP and TSP may use less restrictive (or more liberal) assumptions. The results could be that the TTCs and ATCs are higher than the planned operational parameters, giving rise to potential unreliability. We do not see a problem with the previous wording of “consistent with”, and this should be reinstated. Yes NoWe have the following comments on the VSL: 1. R3: There is a potential overlap between High and Severe. For an ATCID does not include “two or more” of the information items in R3, it could mean does not include all of the information items. This is the same condition as a Severe. We suggest to reword the High VSL to “does not include up to 2 of the information items in R3”; and the Severe VSL to “or its ATCID does not include 3 or more of the information described in R3”, or numbers along that line. 2. We do not agree with the VSLs for R6 and R7 for reasons noted above. We do not see the role of TOP in this standard. The TOP’s primary responsibility is to operate its transmission operating area in a reliable manner, and determine SOLs and where necessary, transmission transfer capabilities and flowgate capabilities (where applicable). Given the established SOLs, TTCs, TFCs that are determined by the TOP for operational planning, and the TTCs and TFCs determined by other entities such as the RCs, TPs and PCs for wider area and for different time frames, the TSP needs only to calculate ATCs (or AFCs) respecting these established constraints. In doing so, it should be able to select an ATC calculation method to suit its business model and needs, with due consideration to the basis of the TTCs and TFCs that affect its service area. With this in mind, we suggest in our response to Q2, above, that the TSP be the one who selects the ATC method and R1 should be revised accordingly. Note also that it should not be assumed that the TOP area and the TSP area are the same and hence the basis of the TTCs and TFCs that affect the TSP’s area may differ from one part to another.
IndividualAlessia DawesHydro One Networks  Yes - definitions are acceptable as revised Transmission Service ProviderThere are 2 methodologies listed in R1. Are these the only two from which we have to choose? We suggest rewording the requirement to avoid this confusion by inserting the words "for example". In R6 and R7, we prefer the previous wording "consistent with" instead of "no more limiting" as the new wording may result in the use of less restrictive assumptions and hence give rise to potential unreliability. Yes NoFor the severe VSL for R2 keep consistent the wording as per the other levels. The Lower, Moderate, and High VSLs for R4 are missing the words "did not". In requirement 8, if the 80 days grace period is to account for software outages then say so explicitly in the requirement else entities may interpret the requirement as applicable to outages other then software.
IndividualJason ShaverAmerican Transmission Company  No - one or more definitions needs revision - see commentsCapitalize "Existing Transmission Commitments" in the Available Transfer capability definition, since it is a defined term. We do not believe that the SDT has to provide a definition of ATCID. Requirement 3 outlines the specifics of ATCID and we find the definition unnecessary. The SDT should explain why this definition is necessary. Transmission OperatorModification to Requirement 1: Each Transmission Operator shall select a methodology for calculating ATC or AFC for each ATC Path or Flowgate for each time period identified in Requirements 2.1 - 2.3 for those Facilities within its Transmission Operators Area. Modifications to 2.2 Daily values for at least the next 31 calendar days (Following the 48 Hours specified in R2.1) Modification to 2.3 Monthly values for at least the next 12 months (Following the 31 Calendar days specified in R2.2) Modification to R3: Each TSP shall prepare and keep current an ATCID that includes the following information. (The Phrase "at a minimum" is unnecessary because the TSP must comply with the sub-requirements. Any additional information is beyond the requirements and therefore not subject to NERC's audit.) Starting in Requirement 3.3 the phrase "transfer or Flowgate capability" is used. Does this phase equate to ATC and AFC where ATC is equal to transfer capability and AFC is equal to Flowgate capability? We would prefer that the SDT remain consistent and use the phrase "ATC or AFC if the phrases are equal. In Requirement 3.3 did the SDT mean "transfer or Flowgate capability" or "transfer of Flowgate capability"? The requirement currently uses the "of" word. In order to maintain a consistent use of the phrase "ATC or AFC" we suggest the following change to Requirement 3.6. "A description of how outages are considered in ATC or AFC calculations including:" The SDT should explain any disagreement with our suggested modification. R5 should be revised to delete the words "all of" to avoid being overly inclusive. R6 should be revised to "no more limiting than those used in the planning of operations." Modifications to R8: The TSP shall recalculate ATC or AFC on the following frequency, unless none of the calculated values identified in the ATC or AFC equations have changed. Question to R8.1: How will the 80 hours per calendar year be calculated? (Does a non-calculation period that is exempt in Requirement 8 count to the 80 hours?) R9 should be revised to eliminate "any" and "all" to avoid being overly inclusive: (1) delete the words "any" from "Within thirty calendar days of receiving a request by any Transmission Service Provider…"; (2) delete the words "all" from "Unit commitments and order of dispatch, to include all designated network resources…"; (3) delete the words "Any" from the phrase "Any firm and non-firm adjustments…"; (4) delete the words "Any" from the phrase "Any other services that that impact ….."; (5) delete the word "all" from "Values of CBM and TRM and TTC for all ATC [paths or Flowgates."; (6) delete "any" from the phrase "any Flowgates considered by the Transmission Service Provider receiving the request…"; (7) delete the word "all" from the phrase "Values of TTC and ATC for all ATC Paths for those…". 5. Delete "all" and "any" in the Measures, the Compliance section, and the Violations Severity Levels 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, AFC, TTC, and TFC). The SDT should provide greater explanation as to what would be the proposed effective data of this standard. FERC has justification over all US users, owners and operators of the BPS and following their approval the standard would become "enforceable". Is the SDT proposing that even in the US these standards will not become "enforceable" until all regulatory authorities including Canada and Mexico have approved this set of standards? If this is the case how would NERC insure such a system of enforcement?
IndividualRex McDanielTexas-New Mexico Power Company  No - one or more definitions needs revision - see commentsAll 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 (TNMP) 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). No Preference Yes Yes This standard should not apply to ERCOT for the reason expressed in question 1.
IndividualTony KroskeyBrazos Electric Power Cooperative, Inc.  No - one or more definitions needs revision - see commentsFor the ERCOT region/market the concept of ATC, AFC are not applicable. It is suggested that the definition of ATC have some consideration for whether there is a required "commercial activity" for it in a region. Transmission Operator     As commented in Question #1, Brazos Electric does not believe that the application of ATC to a single control area region would serve any reliability need or commercial market purpose. Therefore an exclusion should be provided in the requirements based on whether a TO/TOP operates soley in a single control area region.
IndividualRick GonzalesNew York Independent System Operator  No - one or more definitions needs revision - see comments The NYISO has continuing concerns with two of the revised definitions: (i) "ATC Path;" and (ii) "ATC." ATC Path: The NYISO previously expressed concern with the SDT’s use of a new defined term “ATC Path” instead of the term “Posted Path” that was used in earlier versions of MOD-001 and is more consistent with the terminology used in FERC's OASIS posting regulations. The NYISO continues to be concerned that the proposed definition of “ATC Path” set forth in the latest version of proposed MOD-001 could, absent revision or clarification, subject the NYISO to potential penalties that would be inappropriate given the nature of its financial reservation system and the inapplicability of certain OASIS posting requirements to it. Specifically, as the NYISO has explained in previous comments, ATC serves a fundamentally different purpose and is calculated differently in New York, because there are no express physical transmission reservations and all desired uses of the grid are accommodated to the extent that customers are willing to pay congestion. FERC has expressly recognized that the NYISO’s ATC postings are merely advisory projections that may be of some commercial benefit to customers but that they do not determine whether customers can obtain transmission service. The NYISO has also explained that there are no “Posted Paths” as that term is defined under FERC’s OASIS regulations internal to the NYISO and that the NYISO is not required, both because of that fact, and because of FERC orders exempting the NYISO from certain OASIS regulations, to post ATC on its internal interfaces for periods further out than one day-ahead. The current draft of MOD-001 would define “ATC Path” as including both “Posted Paths” and “any other combination of Point of Receipt and Point of Delivery for which Available Transfer Capability is calculated.” The NYISO remains concerned that without clarification this definition could be interpreted in a way that would require the NYISO to post ATC for time periods further out than one day ahead when it is not required by FERC’s regulations to make such postings and where such postings would serve no reliability purpose (because they have nothing to do with scheduling or "over-scheduling" long-term transactions.) Given the nature of the NYISO’s financial reservation system, and the central role that the output of its day-ahead and real-time market software plays in its ATC calculations (see below), the NYISO would not have any meaningful information to post for periods further out than one day-ahead in any case. The NYISO therefore respectfully requests that the SDT either: (i) remove the defined term “ATC Path” and return to the use of “Posted Path” as that term is defined in FERC’s OASIS regulations; or (ii) revise the term “ATC Path” as follows: “ATC Path: Any Posted Path or any other combination of Point of Receipt and Point of Delivery for which Available Transfer Capability is calculated, provided, however, that interfaces or paths for which a Transmission Service Provider is not required under FERC’s regulations, or as a result of FERC orders, to calculate and post ATC for periods further out than one day-ahead shall not be considered to be ATC Paths” The NYISO’s proposed revision would apply to few Transmission Service Providers, and thus would not undermine the proposed requirements or harm reliability. It would, however, be a very important accommodation to the NYISO that would prevent it from being subjected to inappropriate penalties under R1, R2, or R8. Available Transfer Capability (“ATC”): The proposed new definition of “ATC” does not appear to be flexible enough to accommodate the fundamentally different nature of ATC under the NYISO’s FERC-approved financial reservation transmission model. As the NYISO has previously explained, a customer’s ability to schedule transactions in the NYISO system is not limited by a pre-defined amount of ATC. In New York ATC is not, in the SDT’s words, “a measure of the transfer capability remaining in the physical transmission network for further commercial activity over and above already committed uses.” Instead, ATC postings are really “advisory projections” calculated after the NYISO markets close, and transactions are scheduled, based on calculations performed by the NYISO’s day-ahead and real-time market software. The fact that a posted ATC is zero does not mean that further commercial activity is precluded because the NYISO may redispatch its system to support additional transactions. A posted ATC value of zero simply indicates that there is congestion at a particular NYISO interface. FERC has granted the NYISO a number of waivers from its OASIS regulations that reflect these differences and has recognized that ATC is merely an “advisory projection” in New York. The NYISO therefore respectfully requests that the SDT accommodate the different nature of ATC under the NYISO’s FERC-approved financial transmission model by either: (i) deleting the proposed definition of ATC; or (ii) specifying that each Transmission Service Provider must include its definition of ATC in its ATCID (and expressly allowing entities such as the NYISO to have definitions that vary from the standard definition); or (iii) revising the definition as follows: “Available Transfer Capability (ATC): 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 less existing transmission commitments (including retail customer service), less a Capacity Benefit Margin, less a Transmission Reliability Margin, plus Postbacks, plus counterflows, except with respect to Transmission Service Providers that employ FERC-approved financial reservation transmission models in which ATC serves as an advisory projection of potential transmission congestion.” Again, the NYISO’s proposed revision would not apply to many Transmission Service Providers, and thus would not undermine the proposed standard or harm reliability. It would, however, be a very important accommodation to the NYISO that would prevent it from being subjected to inappropriate penalties under R1, R2, R3.6, and R8. Transmission Service Provider The NYISO continues to agree with the ISO/RTO Council that the MOD standards extend into areas that should be covered and addressed by NAESB Business Practices (as defined in MOD-001 Definitions). The frequency of postings and frequency of AFC/ATC calculations should be NAESB Business Practices, and not included in the NERC standards as reliability based requirements Nevertheless, to the extent that the SDT decides to keep such requirements in proposed MOD-001, the NYISO offers the following additional comments or R2, R8, and M2. R2 This requirement continues to reflect an assumption that all Transmission Service Providers are required under FERC’s regulations to calculate and post ATC values for periods 48 hours, one month, and one year into the future. This is not true of the NYISO. Because of the nature of its financial reservation system, FERC has only required the NYISO to calculate and post ATCs for its internal interfaces for a period one day-ahead. The NYISO does not post and calculate, and given the nature of its system, cannot post and calculate, ATCs further out than one day ahead for those internal interfaces or for certain controllable lines that link the NYISO to neighboring Transmission Service Providers. Thus, as drafted, R2 would conflict with FERC orders and FERC approved tariff provisions excusing the NYISO from posting longer range ATCs. It would also require the NYISO to calculate and post ATCs that it cannot practically calculate given the nature of its system (under which ATC is determined primarily by the output of the NYISO’s day-ahead and real-time market software). If R2 is not modified, the NYISO would have to seek a modification (or waiver) from FERC to avoid being subject to penalties for non-compliance with a requirement that should not apply to it. The NYISO respectfully requests that the SDT address the problem by revising proposed R2 as follows: "Each Transmission Service Provider shall calculate ATC or AFC values as listed below using the ATC methodology or methodologies selected by its Transmission Operator(s), except to the extent that the Transmission Service Provider is not required, under FERC’s regulations, or as a result of FERC orders, to calculate and post ATC for periods further out than one day-ahead: [Violation Risk Factor: Lower] [Time Horizon: Operations Planning] R2.1. Hourly ATC values for at least the next 48 hours. R2.2. Daily ATC values for at least the next 31 calendar days. R2.3. Monthly ATC values for at least the next 12 months (months 2-13). In addition, the violation severity levels for these draft standards now have a graded implementation. Nevertheless, it may still be possible for multiple violations to result from a single unintended event. The NYISO requests that double counting of violations for a single event be eliminated by adding a new Item 6 to Section A of the proposed standard to establish this point. R8 The NYISO has previously asked the SDT to clarify or revise R8 so that Transmission Service Providers such as the NYISO that are not required to post monthly ATC values for internal interfaces (See the NYISO's response to Question One, above) would not be subject to a requirement to recalculate such values on a weekly basis. Otherwise, R8 would effectively require the NYISO to conduct calculations that FERC has excused it from conducting and that would serve no reliability purpose under the NYISO's financial reservation transmission model. The NYISO therefore respectfully requests that the SDT revise R8 to to clearly establish that Transmission Service Providers need not recalculate ATC values that they are not required to calculate or post under FERC’s regulations, or as a result of FERC orders M2 Consistent with the NYISO's comments on R2 and R8, and with past NYISO comments, NERC should revise M2 to clearly state that Transmission Service Providers need not provide evidence that they calculated ATCs that they are not required to calculate or post under FERC’s regulations, or as a result of FERC orders Yes NoThe NYISO agrees with the ISO/RTO Council comments on this issue. NERC 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 NYISO remains concerned regarding the possibility of multiple violations resulting from a single event. Therefore, the NYISO requests that double counting of violations for a single event be eliminated. A single event shall not result in multiple violations.