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Ballot Results
Ballot Name: ATC-TTC-CBM-MOD-004_in
Ballot Period: 3/3/2008 - 3/12/2008
Ballot Type: Initial
Total # Votes: 173
Total Ballot Pool: 186
Quorum: 93.01 %  The Quorum has been reached
Weighted Segment Vote:

38.80 %

Ballot Results: The ballot has closed
Summary of Ballot Results
Segment Ballot
Pool
Segment
Weight
Affirmative Negative No
Vote
# Votes Fraction # Votes Fraction Negative Vote
without a Comment
Abstain
          
1 - Segment 157 1 19 0.463 22 0.537 0124
2 - Segment 210 0.8 3 0.3 5 0.5 011
3 - Segment 343 1 14 0.4 21 0.6 062
4 - Segment 48 0.6 2 0.2 4 0.4 020
5 - Segment 529 1 8 0.381 13 0.619 062
6 - Segment 624 1 5 0.278 13 0.722 042
7 - Segment 71 0 0 0 0 0 010
8 - Segment 82 0.1 0 0 1 0.1 001
9 - Segment 96 0.5 3 0.3 2 0.2 010
10 - Segment 106 0.5 2 0.2 3 0.3 001
Totals1866.5562.522843.97803313
Individual Ballot Pool Results
Segment Organization Member Ballot NERC Notes
     
1Allegheny PowerRodney Phillips Abstain
1American Transmission Company, LLCJason Shaver
1Associated Electric Cooperative, Inc.John Bussman Affirmative
1Avista Corp.Scott Kinney Affirmative
1Bonneville Power AdministrationDonald S. Watkins Affirmative The purpose statement for MOD-004 should be expanded, to describe the timeframe for which CBM is to be activated so as not to conflict with TRM, to include a statement that “CBM is to be scheduled by the Energy Deficient Entity experiencing a declared NERC Energy Emergency Alert (EEA) 2 or higher only in the hour following a generation forced outage event."
1CenterPoint EnergyPaul Rocha Negative ERCOT’s filed comments to the SDT that ATC, TTC, CBM, and TRM are not applicable within ERCOT operations and that these Standards should have provisions that make it clear that these requirements apply only within market structures in which they are pertinent were ignored by the SDT. These standards should not apply to ERCOT, thus our negative vote.
1City of TallahasseeGary S. Brinkworth Affirmative
1Consolidated Edison Co. of New YorkEdwin E Thompson Negative PSRG is not an entity defined in the NERC functional Model, too many changes to requirements from last draft – this is not following standards development process – standard should be out for comments again, not up for approval vote.
1Duke Energy CarolinaDouglas E. Hils Abstain
1East Kentucky Power Coop.George S. Carruba
1El Paso Electric CompanyDennis Malone Abstain
1Entergy CorporationGeorge R. Bartlett Affirmative
1Exelon EnergyJohn J. Blazekovich Negative R1.5. A statement should be added to confirm that it shall use assumptions in calculating CBM that are consistent with those assumptions that are used in the Transmission planning process "
1FirstEnergy Energy DeliveryRobert Martinko Negative FirstEnergy Corp. (FE) appreciates the hard work put forth by NERC’s ATC Standard Drafting Team. We offer the following general comments in addition to our specific standard comments presented below. CBM & TRM – MARKET AREAS: FE supports the drafting team’s approach of three ATC methodologies presented in MOD-028, MOD-029 and MOD-030 to account for differences in calculating ATC in various geographic areas of the bulk electric system. However, the use of a single standard methodology for CBM and TRM as currently written does not meet the needs for entities operating within a market area such as MISO, PJM etc. FE suggests that various requirements in the proposed standards that are currently applicable to the TP and TOP are actually handled by the RTO and within a market area would more appropriately be assigned to the Planning Coordinator (PC) and Reliability Coordinator (RC), respectively. This change would allow the proposed standards for CBM and TRM to be used largely “as is” within both market and non-market areas as the PC and RC would be appropriate in both. Our comments below on specific MOD standards elaborate on this point and provide examples where we feel the applicability is inappropriately assigned to TP or TOP responsible entities within a transmission market construct. DECISION TO BALLOT: While the MOD standards presented are improving in content FE believes the standards should have been issued for one more comment period prior to ballot per the NERC Standard Development Procedures (SDP). In many cases this is only the 2nd draft version being reviewed by industry. The objective during the “Solicit Public Comments on Draft Standard (Step 6)” of the NERC SDP is to “Receive stakeholder inputs on the draft standard for the purpose of assessing consensus on the draft standard, and modifying the draft standard as needed to improve consensus.” Based on the 200+ pages of comments of the prior draft version it is hard to conclude that the industry was near consensus. Additionally, per the SDP, now that the standards have gone to First Ballot (Step 9), the standard drafting team is not permitted to make any changes to the standards based on comments received during this First Ballot. The drafting team will now be required to rely on their responses to industry feedback to try and improve consensus during a re-circulation ballot. FE has concerns with the consequences of this decision with regard to the integrity of the standard development process and substantive registered entity perspectives. FirstEnergy Corp. (FE) appreciates the hard work put forth by NERC’s ATC Standard Drafting Team. However, at this time, FE is voting Negative to this standard with the following comments and suggestions: The Planning Coordinator (PC) should replace the Transmission Planner (TP) as the applicable entity. The requirements in R5 and R7 should be the ultimate responsibility of the PC who works with his associated TP to obtain the necessary information. Per the NERC functional model, the PC “coordinates and collects data for system modeling from the Transmission Planner…” and “coordinates total transfer capability with Transmission Planners…”. This standard is too prescriptive with the detail into how CBM should be calculated across all interconnections and does not take into account all the different calculation methods currently used by various entities in the industry. It is suggested that the standard be more general and that some of the information contained is better suited with a guideline document for calculating CBM.
1Florida Power & Light Co.C. Martin Mennes Abstain
1Gainesville Regional UtilitiesLuther E. Fair Affirmative
1Georgia Transmission CorporationHarold Taylor, II Affirmative
1Great River EnergyGordon Pietsch Negative GRE agrees with the PJM and MISO recommendation that the standard needs an additional commenting period based on the significance of the comments submitted during the previous commenting periods.
1Hydro One Networks, Inc.Ajay Garg Negative Hydro One Networks Inc. is casting a negative vote on the 6 MOD standards (MOD-001, MOD-004, MOD-008, MOD-28, MOD-029 and MOSD-030) We believe there is a fundamental issue related with effective dates, that is, the dates in which Reliability Standards become effective and enforceable. In principle, the effective date of standards must be the same for all jurisdictions in North America. It does not make sense that there is a period of time when a standard is effective only in some jurisdictions while not in others. This is particularly important in the MOD Standards in ballot as they have implications on neighbouring areas. The words inserted in the Effective Date of the Standards as well as in the Implementation Plan document permit that these Standards are effective in some jurisdictions and not others. These Standards should be modified to ensure that they become effective in all jurisdiction at the same time, including those where such regulatory approval in not required that is, only when all regulatory approvals have been obtained, In addition we offer the following comments to the specific Standard MOD-004-1: (a) Requirement 1.1 introduces the concept of an entity called the Planned Resource Sharing Group. This entity is not defined and is not currently in the approved version of the NERC Functional Model (v.3). Adding this entity raises issues for registration and compliance. (b) Requirements have been introduced for the first time in this version. None of these revisions have yet been posted for comments by the industry. New requirements should not be introduced in the final version of a standard without affording the industry some opportunity to comment. This bypasses the intent of the ANSI approved NERC RS process.
1Hydro-Quebec TransEnergieJulien Gagnon Negative Requirement 1.1 adds the concept of Planned Resource Sharing Group. This entity is not defined and is not currently in NERC Functionnal Model (v.3). Adding entity is risky and raises the issue of registration. Should such a Planned Resource Sharing Group register even if it's not an entity defined in NERC Functionnal Model ? If not, what are the consequences ? It seems that the idea was to address the situation where an ISO, for example, would do it for other entities. We oppose the idea of introducing new entities in a standard. Moreover, many requirements are introduced for the first time in this version. None of these have thus been circulated for comment in the previous rounds. New requirements can't be introduced in the final version of a standard. It doesn't respect the voting process.
1Idaho Power CompanyRonald D. Schellberg Affirmative
1Kansas City Power & Light Co.James Useldinger Negative The CBM calculation should not be applicable to the LSE. Suggest removing LSE from applicability.
1Lakeland ElectricLarry E Watt Affirmative
1Lincoln Electric SystemDoug Bantam Negative
1Metropolitan Water District of Southern CaliforniaGarry Chinn Abstain
1Municipal Electric Authority of Georgia Jerry J Tang Negative The Requirement R.8 implies that this standard would require TSPs to furnish CBM to “entities” that never requested or funded CBM. This unreasonable interpretation is expected to cause reliability problems for LSEs that currently rely on CBM. From the proposed standard, some may even infer that all “entities” affiliated with the TSP’s BA have an entitlement to use the TSP’s CBM even if, for example, such “entities” have no transmission service contract with the TSP or such “entities” are insolvent. An obvious alternative interpretation, consistent with the terminology used in R.10, is that TSPs may reasonably conclude that CBM is not AVAILABLE to entities that have not made a valid CBM request (except to extent CBM capacity is released and purchased non-firm). Furthermore, the standard is silent on whether a TSP may prioritize competing requests to use CBM. Is the CBM first come, first served without any consideration of whether the requestor complied with the TSP’s CBMID? If an LSE that reserved CBM loses a generator after all the CBM is in use by other “entities” that never requested CBM, does the TSP deny CBM to the LSE that requested and paid for it? Undoubtedly, if this standard is approved without changes, it would have to raise questions if the drafting team’s interpretation comports with the Takings Clause of the Fifth Amendment to the U.S. Constitution. Finally, while some may argue that the drafting team’s interpretation will improve reliability for customers of systems that are short on installed capacity (and this may be the case in the short-run), the unintended consequence is that entities that may already be irresponsibly under-resourced may further reduce their installed capacity investments once they learn they can free ride on their neighbors’ CBM.
1National GridMichael J Ranalli Negative This standard has added in the applicability section, an entity referred to as a Planned Resource Sharing Group. Requirement 1.1 adds this concept of an entity called the Planned Resource Sharing Group. This entity is not defined and is not currently in the latest approved version of the NERC Functional Model (v.3). Adding this entity raises issues for registration and compliance. Additionally and more importantly, requirements have been introduced for the first time in this version of the standard. None of these revisions have yet been circulated for comment. New requirements should not be introduced in the final version of a standard without affording the industry some opportunity to comment. This, in our view bypasses the intent of the ANSI approved NERC RS process.
1Nebraska Public Power DistrictRichard L. Koch Negative
1New Brunswick Power Transmission CorporationWayne N. Snowdon Negative There are new requirements introduced in this version that have not been circulated for comment. Requirement 1.1 adds and entity that has not been defined and is not in the current version fo the NERC Functional model.
1New York Power AuthorityRalph Rufrano Negative problems were found with the applicability section as it pertains to the planned resource sharing group. Requirement 1.1 adds this concept of an entity called the Planned Resource Sharing Group. This entity is not defined and is not currently in the latest approved version of the NERC Functional Model (v.3). Adding this entity raises issues for registration and compliance. Additionally, requirements have been introduced for the first time in this version. None of these revisions have yet been circulated for comment. New requirements should not be introduced in the final version of a standard without affording the industry some opportunity to comment. This, in the view of the RSC bypasses the intent of the ANSI approved NERC RS process.
1Northeast UtilitiesDavid H. Boguslawski Negative The Applicability - Functional Entity section identifies the Planned Resource Sharing Group, which is not a functional entity identified in the lastest version of the NERC Functional Model. Additionally, a number of requirements were added after the last posting which were not reposted for comments, and therefore bypassed the established standard development process.
1Ohio Valley Electric Corp.Robert Mattey Affirmative
1Oklahoma Gas and Electric Co.Marvin E VanBebber Affirmative
1Omaha Public Power DistrictLorees Tadros
1Oncor Electric DeliveryCharles W. Jenkins Abstain
1Orlando Utilities CommissionBrad Chase Negative
1Otter Tail Power CompanyLawrence R. Larson Negative
1PacifiCorpRobert Williams Abstain
1Platte River Power AuthorityJohn C. Collins Affirmative
1Portland General Electric Co.Frank F. Afranji Affirmative
1Potomac Electric Power Co.Richard J. Kafka Negative Potomac Electric agrees with the comments of PJM distributed to the ballot body. I will not repeat them here, but do include the headings: I. The ATC MOD standards should have been sent out for comment not pre-ballot posting. II. Depth of the ATC MOD standards is excessive. III. Determining Violation Risk Factors is incorrect. IV. Determining Violation Severity Levels is incomplete.
1PP&L, Inc.Ray Mammarella Abstain
1Public Service Electric and Gas Co.Kenneth D. Brown Negative PSE&G votes NO for the reasons expressed in PJM’s comments.
1Sacramento Municipal Utility DistrictDilip Mahendra Affirmative
1Salt River ProjectRobert Kondziolka Affirmative
1Santee CooperTerry L. Blackwell Negative The drafting team's response to Entergy regarding MOD-004-1 Requirement 8 implies that this standard would require a Transmission Service Provider to furnish CBM to any LSE or "entity" that never requested or funded CBM. Another unintended consequence of Requirement 8 is that entities (some that may already be irresponsibly under-resourced) may further reduce their installed capacity investments once they learn they can free ride on their neighbors' CBM.
1SCE&GHenry Delk, Jr. Negative
1Seattle City LightChristopher M. Turner Affirmative
1Sierra Pacific Power Co.Richard Salgo Abstain I respecfully abstain from this ballot, as CBM is not currently a product that is utilized within our environment. Nonetheless, I would point out that there is no Reliability impact of any of the Requirements in the Standard.
1Southern California Edison Co.Dana Cabbell Abstain
1Southern Company Services, Inc.Horace Stephen Williamson Affirmative We applaud the great work of the standard drafting team. While the current version is "workable" by Industry, it is recommended that only the LSE be applicable. There is not a PRSG function for which NERC can audit compliance. Additionally, the PRSG is a business arrangement and is not considered a reliability issue.
1Southwest Transmission Cooperative, Inc.James L. Jones Affirmative
1Transmission Agency of Northern CaliforniaJames W. Beck Abstain
1Tucson Electric Power Co.Ronald P. Belval
1Westar EnergyAllen Klassen Negative Why not applicable to Planning Authority ?? R1.4 and 4.2.1 and 4.2.2 ATC or AFC should NEVER be allowed to beless than zero. R3.1 should be Planning Authority instead of Transmission Planner. R3.2 Every 31 days not needed for many LSEs, this is onerous
1Western Area Power AdministrationRobert Temple Abstain Only those that post CBM need to document it. No Western office utilizes CBM.
1Xcel Energy, Inc.Gregory L Pieper Affirmative
2Alberta Electric System OperatorAnita Lee Abstain
2British Columbia Transmission CorporationPhil Park Affirmative
2California ISODavid Hawkins Affirmative
2Electric Reliability Council of Texas, Inc.Roy D. McCoy Affirmative
2Independent Electricity System OperatorKim Warren Negative In the applicability section, there is an entity – “Planned Resource Sharing Group” that is not a defined term in the latest version of the Functional Model. Additionally, there are a number of changes that have been made to the draft standard which have not been vetted with the industry but instead the SDT decided to go straight to the ballots instead. Hence we decided to vote against this standard
2ISO New England, Inc.Kathleen Goodman Negative The applicability section indicates a planned resource sharing group which is not a functional entity identified in the lastest version of the NERC Functional Model. Therefore, this Standard is not enforceable. Also, a number of requirements were added after the last posting which were not reposted for comments. WE believe this is a violation of the established standard development process.
2Midwest ISO, Inc.Terry Bilke Negative
2New Brunswick System OperatorAlden Briggs
2New York Independent System OperatorGregory Campoli Negative The NYISO does not use CBM and interprets the revised “Applicability” provision of MOD-004 as confirming that it will not be required to have or maintain a CBMID so long as that is the case. Nevertheless, the NYISO is voting against MOD-004 for the “general” reasons specified in its response to MOD-001, namely the fact that the proposed standard is overly detailed and addresses areas that are better left to NAESB or to the individual practices of individual practices of Reliability Coordinators, Transmission Operators, Transmission Service Providers, Transmission Planners, etc. The NYISO also agrees with the NPCC that the latest version of MOD-004 inappropriately adds a new entity, and new requirements. Both additions raise issues that should be discussed more fully in comments before they are approved by NERC.
2PJM Interconnection, L.L.C.Tom Bowe Negative MOD-004 Specific Comments: The ATC MOD standards should have been sent out for comment not pre-ballot posting. The SDT recognized that there were 3 different ways of calculating ATC and wrote MOD028-1, MOD029-1, and MOD030-1 as individual standards for each method. The SDT should be consistent in its approach and develop a second standard for CBM and cover both of the existing methods. MOD004 as written assumes individual LSEs determine their emergency generation requirements and manage them with requests to the TSP. The standard was modified to recognize aggregating LSEs termed Planned Resource Sharing Group to recognize a different method of implementing CBM. This change falls short in that requirements still exist that are unique to the LSE method such as the processing of individual requests. The standard fails to recognize that individual instances of load import emergencies may be met through other means. A second CBM standard should be written to represent the wider implementation of CBM on a regional basis and recognize the current practices used by ISO/RTOs or other regional entities. ISOs may manage the load emergencies using remote generation within its zone. This standard assumes all LSE GCIR is from outside the TSP zone by requiring the LSE to specify the GCIR and to match the request with transmission service set aside as CBM (imported from external resources). A single approach to CBM would result in a required methodology which does not represent how operations are conducted in large parts of the system. PJM believes no requirement from the 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. Requirement 1 • R1.3 should not be applicable in the event that a BA manages utilization of the transmission system and manages imports in emergency conditions on behalf of LSEs. • R1.4. A statement of whether the Transmission Service Provider allows ATC or AFC to be less than zero due to CBM has no meaning outside of R4.3 and should not be an independent requirement. Requirement 3 • R3 The timelines specified should be superseded by PRSG agreements. Existing processes should not be modified simply to meet requirements specified by this standard when reliability shortcomings do not exist. These timelines are best left as NAESB scope. • R3.1.1.1 is an awkward way of saying provide monthly values if your procedures are based on a monthly process or provided yearly if it’s based on a yearly paradigm. Again this should be considered NAESB scope. ISOs that find it prudent to determine CBM on a planning timeline should not be required to respond to CBM changes on a short term basis. CBM should be determined on a timeline that allows the entities to respond to a condition of insufficient import capability. Building new infrastructure requires planning several years out. CBM could be evaluated on a short term basis to be released to the market for sale but this is NAESB scope. A second CBM standard should contain requirements that recognize this planning timeline focused method, or this requirement should be removed. • R3.1.1.4 There are probabilistic methods that don’t use a prescribed source for the evaluation. In ISOs the load requirements may be met by a mix of a number of generation sources several busses away. This standard should not restrict methods currently implemented that do not require the generator to be specified. Such a requirement may restrict markets and is not in line with NERC or FERC’s intent in developing standards. • R3.1.2.1 This requirement recognizes there may be different implementations other than the requirement in R3.1.1. This underscores the fact that these requirements are written to achieve an objective, which is a calculated and respected CBM value verses a required process of exactly ‘How’ CBM must be calculated. • R3.2 In the context described above this monthly requirement is inappropriate. This requires a monthly re-evaluation of a yearly margin determined 5 years ago. If the requirement is to ensure a release of CBM to the market if the margin is not used then that is NAESB scope. Requirement 4 • R4 The timelines specified should not apply to entities with existing processes that determine CBM on a Planning timeframe. These timelines should be eliminated or a second CBM standard would address the appropriate timelines for such entities. • R4.3.1, R4.3.2 This is a procedure and doesn’t belong in a standard. This appears to codify a business practice regarding the treatment of a negative ATC if CBM is applied. • Requirement 6 • R6 is inappropriate for BAs that manage emergency situations by redirecting or redispatching within their network. R6 should be eliminated. Requirement 8 • R8 – A BA is not required to schedule energy. A BA may manage the import of energy during load emergencies. This requirement should be modified if a second CBM standard is not written.
3Alabama Power CompanyRobin Hurst Affirmative We applaud the great work of the standard drafting team. While the current version is "workable" by Industry, it is recommended that only the LSE be applicable. There is not a PRSG function for which NERC can audit compliance. Additionally, the PRSG is a business arrangement and is not considered a reliability issue.
3Allegheny PowerBob Reeping Abstain
3American Electric PowerRaj Rana Abstain
3Arizona Public Service Co.Thomas R. Glock Affirmative
3Atlantic City Electric CompanyJames V. Petrella Negative
3BC Hydro and Power AuthorityPat G. Harrington Abstain
3Bonneville Power AdministrationRebecca Berdahl Affirmative The purpose statement for MOD-004 should be expanded, to describe the timeframe for which CBM is to be activated so as not to conflict with TRM, to include a statement that “CBM is to be scheduled by the Energy Deficient Entity experiencing a declared NERC Energy Emergency Alert (EEA) 2 or higher only in the hour following a generation forced outage event."
3City of TallahasseeRusty S. Foster Negative
3City Public Service of San AntonioEdwin Les Barrow Affirmative
3Commonwealth Edison Co.Stephen Lesniak Negative
3Consolidated Edison Co. of New YorkPeter T Yost Negative PSRG is not an entity defined in the NERC functional Model.
3Delmarva Power & Light Co.Michael R. Mayer Negative
3Dominion Resources, Inc.Jalal (John) Babik Negative In support of PJM and NPCC comments
3Duke Energy CarolinaHenry Ernst-Jr Abstain
3Entergy Services, Inc.Matt Wolf Affirmative
3Farmington Electric Utility SystemAlan Glazner Negative
3FirstEnergy SolutionsJoanne Kathleen Borrell Negative FirstEnergy Corp. (FE) appreciates the hard work put forth by NERC’s ATC Standard Drafting Team. We offer the following general comments in addition to our specific standard comments presented below. CBM & TRM – MARKET AREAS: FE supports the drafting team’s approach of three ATC methodologies presented in MOD-028, MOD-029 and MOD-030 to account for differences in calculating ATC in various geographic areas of the bulk electric system. However, the use of a single standard methodology for CBM and TRM as currently written does not meet the needs for entities operating within a market area such as MISO, PJM etc. FE suggests that various requirements in the proposed standards that are currently applicable to the TP and TOP are actually handled by the RTO and within a market area would more appropriately be assigned to the Planning Coordinator (PC) and Reliability Coordinator (RC), respectively. This change would allow the proposed standards for CBM and TRM to be used largely “as is” within both market and non-market areas as the PC and RC would be appropriate in both. Our comments below on specific MOD standards elaborate on this point and provide examples where we feel the applicability is inappropriately assigned to TP or TOP responsible entities within a transmission market construct. DECISION TO BALLOT: While the MOD standards presented are improving in content FE believes the standards should have been issued for one more comment period prior to ballot per the NERC Standard Development Procedures (SDP). In many cases this is only the 2nd draft version being reviewed by industry. The objective during the “Solicit Public Comments on Draft Standard (Step 6)” of the NERC SDP is to “Receive stakeholder inputs on the draft standard for the purpose of assessing consensus on the draft standard, and modifying the draft standard as needed to improve consensus.” Based on the 200+ pages of comments of the prior draft version it is hard to conclude that the industry was near consensus. Additionally, per the SDP, now that the standards have gone to First Ballot (Step 9), the standard drafting team is not permitted to make any changes to the standards based on comments received during this First Ballot. The drafting team will now be required to rely on their responses to industry feedback to try and improve consensus during a re-circulation ballot. FE has concerns with the consequences of this decision with regard to the integrity of the standard development process and substantive registered entity perspectives. FirstEnergy Corp. (FE) appreciates the hard work put forth by NERC’s ATC Standard Drafting Team. However, at this time, FE is voting Negative to this standard with the following comments and suggestions: The Planning Coordinator (PC) should replace the Transmission Planner (TP) as the applicable entity. The requirements in R5 and R7 should be the ultimate responsibility of the PC who works with his associated TP to obtain the necessary information. Per the NERC functional model, the PC “coordinates and collects data for system modeling from the Transmission Planner…” and “coordinates total transfer capability with Transmission Planners…”. This standard is too prescriptive with the detail into how CBM should be calculated across all interconnections and does not take into account all the different calculation methods currently used by various entities in the industry. It is suggested that the standard be more general and that some of the information contained is better suited with a guideline document for calculating CBM.
3Florida Municipal Power AgencyMichael Alexander Negative We believe this standard needs an additional commenting period.
3Florida Power & Light Co.W. R. Schoneck Affirmative
3Georgia Power CompanyLeslie Sibert Affirmative We applaud the great work of the standard drafting team. While the current version is "workable" by Industry, it is recommended that only the LSE be applicable. There is not a PRSG function for which NERC can audit compliance. Additionally, the PRSG is a business arrangement and is not considered a reliability issue
3Georgia System Operations CorporationEdward W. Pourciau Affirmative
3Great River EnergySam Kokkinen Negative
3Gulf Power CompanyGwen S Frazier Affirmative We applaud the great work of the standard drafting team. While the current version is "workable" by Industry, it is recommended that only the LSE be applicable. There is not a PRSG function for which NERC can audit compliance. Additionally, the PRSG is a business arrangement and is not considered a reliability issue.
3Hydro One Networks, Inc.Michael D. Penstone Negative Hydro One Networks Inc. is casting a negative vote on the 6 MOD standards (MOD-001, MOD-004, MOD-008, MOD-28, MOD-029 and MOSD-030) We believe there is a fundamental issue related with effective dates, that is, the dates in which Reliability Standards become effective and enforceable. In principle, the effective date of standards must be the same for all jurisdictions in North America. It does not make sense that there is a period of time when a standard is effective only in some jurisdictions while not in others. This is particularly important in the MOD Standards in ballot as they have implications on neighbouring areas. The words inserted in the Effective Date of the Standards as well as in the Implementation Plan document permit that these Standards are effective in some jurisdictions and not others. These Standards should be modified to ensure that they become effective in all jurisdiction at the same time, including those where such regulatory approval in not required that is, only when all regulatory approvals have been obtained. In addition we offer the following comments to the specific Standard MOD-004: (a) Requirement 1.1 introduces the concept of an entity called the Planned Resource Sharing Group. This entity is not defined and is not currently in the approved version of the NERC Functional Model (v.3). Adding this entity raises issues for registration and compliance. (b) Requirements have been introduced for the first time in this version. None of these revisions have yet been posted for comments by the industry. New requirements should not be introduced in the final version of a standard without affording the industry some opportunity to comment. This bypasses the intent of the ANSI approved NERC RS process.
3Kissimmee Utility AuthorityGregory David Woessner
3Lincoln Electric SystemBruce Merrill Negative LES agrees with the PJM and MISO recommendation that the standard needs an additional commenting period.
3Louisville Gas and Electric Co.Charles A. Freibert Negative
3MidAmerican Energy Co.Thomas C. Mielnik Negative I agree with the PJM that this standard needs another commenting period.
3Mississippi PowerDon Horsley Affirmative We applaud the great work of the standard drafting team. While the current version is "workable" by Industry, it is recommended that only the LSE be applicable. There is not a PRSG function for which NERC can audit compliance. Additionally, the PRSG is a business arrangement and is not considered a reliability issue.
3Municipal Electric Authority of Georgia Steven M. Jackson Negative The drafting team’s response to Entergy regarding MOD-004-1 requirement 8 implies that this standard would require TSPs to furnish CBM to “entities” that never requested or funded CBM. This unreasonable interpretation is expected to cause reliability problems for LSEs that currently rely on CBM. From the drafting team’s reply some may even infer that all “entities” have an entitlement to use a TSP’s CBM even if, for example, such “entities” have no transmission service contract with the TSP or such “entities” are insolvent. An obvious alternative interpretation, consistent with the terminology used in requirement 10, is that TSPs may reasonably conclude that CBM is not AVAILABLE to entities that have not made a valid CBM request (except to extent CBM capacity is released and purchased non-firm). Furthermore, the drafting team’s interpretation raises questions not envisioned when we conducted our review of the draft standard. For example, the standard is silent on whether a TSP may prioritize competing requests to use CBM. Is the CBM first come, first served without any consideration of whether the requestor complied with the TSP’s CBMID? If an LSE that reserved CBM loses a generator after all the CBM is in use by other “entities” that never requested CBM, does the TSP deny CBM to the LSE that requested and paid for it? Undoubtedly, if FERC approves this standard without changes, it would have to raise questions if the drafting team’s interpretation comports with the Takings Clause of the Fifth Amendment to the U.S. Constitution. Finally, while some may argue that the drafting team’s interpretation will improve reliability for customers of systems that are short on installed capacity (and this may be the case in the short-run), the unintended consequence is that entities that may already be irresponsibly under-resourced may further reduce their installed capacity investments once they learn they can free ride on their neighbors’ CBM.
3New York Power AuthorityChristopher de Graffenried Negative 2) MOD-004-1--recommendation to vote NO not to accept. NPCC RSC found problems with the applicability section as it pertains to the planned resource sharing group. Requirement 1.1 adds this concept of an entity called the Planned Resource Sharing Group. This entity is not defined and is not currently in the latest approved version of the NERC Functional Model (v.3). Adding this entity raises issues for registration and compliance. Additionally, requirements have been introduced for the first time in this version. None of these revisions have yet been circulated for comment. New requirements should not be introduced in the final version of a standard without affording the industry some opportunity to comment. This, in the view of the RSC bypasses the intent of the ANSI approved NERC RS process.
3North Carolina Municipal Power Agency #1Denise Roeder Abstain
3Orlando Utilities CommissionBallard Keith Mutters Abstain
3PECO Energy an Exelon Co.John J. McCawley Negative R1.5. A statement should be added to confirm that it shall use assumptions in calculating CBM that are consistent with those assumptions that are used in the Transmission planning process.
3Platte River Power AuthorityTerry L Baker Affirmative
3Public Service Electric and Gas Co.Jeffrey Mueller Negative PSE&G votes NO for the reasons expressed in PJM’s comments.
3Santee CooperZack Dusenbury Negative The drafting team's response to Entergy regarding MOD-004-1 Requirement 8 implies that this standard would require a Transmission Service Provider to furnish CBM to any LSE or "entity" that never requested or funded CBM. Another unintended consequence of Requirement 8 is that entities (some that may already be irresponsibly under-resourced) may further reduce their installed capacity investments once they learn they can free ride on their neighbors' CBM.
3Seattle City LightDana Wheelock Affirmative
3South Carolina Electric & Gas Co.Hubert C. Young
3Tampa Electric Co.Ronald L Donahey Affirmative
3Wisconsin Electric Power MarketingJames R. Keller Negative GCIR definition - We are uncomfortable with the definition of GCIR, especially with no guidance on the determination or use of this quantity. Additionally it is not specified whether this is a maximum or average over the period in question. PRSG definition - The definition states that this is an agreement to jointly meet a resource adequacy requirement, there are some PRSG's that are just doing a "joint study" to determine a requirement but how they meet that requirement may be unique to the LSE. R4.1.2 - The determination of the CBM seems to be disconnected from the current resource adequacy methodology processes that are being used in most RTO's. I.e. a difference in models could induce inconsistencies in the CBM that is actually available and the reserve margins identified in the resource adequacy studies. R4.3 - It is difficult to tell whether the process is a "first come first served" process or whether all CBM requests are evaluated on a common basis. R7 - There should be a consideration to providing these studies to LSE's to assist in coordination of methodologies etc. Measures, M3 - The words "that wants CBM" could be better stated as "is requesting CBM to support the calculated reserve margin"
3Wisconsin Public Service Corp.James Maenner Negative WPSC agrees with the PJM and MISO recommendation that the standard needs an additional commenting period .
3Xcel Energy, Inc.Michael Ibold Affirmative
4American Public Power AssociationAllen Mosher Abstain
4Consumers Energy David Frank Ronk Affirmative
4Florida Municipal Power AgencyRalph Anderson Negative We believe this standard needs an additional commenting period.
4Indiana Municipal Power AgencyGayle Mayo Abstain
4Integrys Energy Group, Inc.Christopher Plante Negative Standard MOD-004 is confusing in that it mixes the use of Generation Capability Import Requirement (GCIR) and CBM. If GCIR and CBM are intended to reflect different quantities, the standard should provide a definition for CBM. The standard needs to clearly reference GCIR and CBM throughout the document, consistent with their definitions. The definition of PRSG should reflect the intent of a PRSG - to collectively assess the resource adequacy of a group of LSEs. The current definition inappropriately refers to a "resource adequacy requirement" which EPAct 2005 prohibits FERC and the ERO from establishing. Also, the current definition suggests a sharing of "planned resources" rather than a sharing of "planning reserves". Suggest the following definition for PRSG (consistent with MRO's approved Resource Adequacy Assessment standard): Planned Reserve Sharing Group (“PRSG”) is defined as a group of Load Serving Entities (“LSEs”) that agree to study their collective resources to assess the planned Resource Adequacy for the load of the PRSG as a whole. R2 - the CBMID should be made available to everyone, not just TOs, TPs, RCs, and transmission planners. In order to provide for transparency and consistency, the CBM Implementation Document should be available to all users, owners, and operators of the transmission system. R7 - same comment as R2 - the allocation of CBM over different ATC/AFC paths must be available to all users, owners, and operators. Requirement R3.1.2 references entities that do not have the ability to establish resource adequacy assessment requirements. Only the Regional Entities, through their ANSI approved standards setting process and delegated authority, can establish requirements for resource adequacy assessment. R3.1.2 should refer to FERC approved standards only. R3.3 The request for CBM should be based on the resource adequacy assessment criteria of the REs only. Only the REs have the ANSI accredited processes and delegated authority to establish resource adequacy assessment criteria. R4.2.1 and R4.3.1 - both of these requirements allow the TP to unilaterally reduce the CBM requested by LSEs. While TPs should have the ability to post negative ATC/AFC as zero, the TP should not have the right to reduce the CBM of the LSEs. M5 refers to “regional generation reliability criteria”. Generation reliability criteria are different than resource adequacy assessment criteria. M5 should only reference the later.
4Madison Gas and Electric Co.Joseph G. DePoorter Negative We agree with the PJM and MISO recommendation that the standard needs an additional commenting period .
4Seattle City LightHao Li Affirmative
4Wisconsin Energy Corp.Anthony Jankowski Negative GCIR definition - We are uncomfortable with the definition of GCIR, especially with no guidance on the determination or use of this quantity. Additionally it is not specified whether this is a maximum or average over the period in question. PRSG definition - The definition states that this is an agreement to jointly meet a resource adequacy requirement, there are some PRSG's that are just doing a "joint study" to determine a requirement but how they meet that requirement may be unique to the LSE. R4.1.2 - The determination of the CBM seems to be disconnected from the current resource adequacy methodology processes that are being used in most RTO's. I.e. a difference in models could induce inconsistencies in the CBM that is actually available and the reserve margins identified in the resource adequacy studies. R4.3 - It is difficult to tell whether the process is a "first come first served" process or whether all CBM requests are evaluated on a common basis. R7 - There should be a consideration to providing these studies to LSE's to assist in coordination of methodologies etc. Measures, M3- The words "that wants CBM" could be better stated as "is requesting CBM to support the calculated reserve margin"
5AEP Service Corp.Brock Ondayko Abstain
5Avista Corp.Edward F. Groce Affirmative
5BC Hydro and Power AuthorityClement Ma Affirmative
5Bonneville Power AdministrationFrancis J. Halpin Affirmative The purpose statement for MOD-004 should be expanded, to describe the timeframe for which CBM is to be activated so as not to conflict with TRM, to include a statement that “CBM is to be scheduled by the Energy Deficient Entity experiencing a declared NERC Energy Emergency Alert (EEA) 2 or higher only in the hour following a generation forced outage event."
5Calpine CorporationJohn B. Hebert Negative The former NERC standard for ATC required that TSPs have and publish their methodology for calculation of ATC. Such a standard has clearly been rejected by FERC, instead opting for much greater transparency. However, we note that amongst the redlined changes in the version of MOD-001 that is being balloted, the word “transparency” has been deleted from the purpose. We also note that Requirement R3.1 requires that sufficient data will be exchanged to allow for validation of the ATC calculation but in response to EPSA and many others it is clear that NERC will not mandate what if any of this data will be shared with market participants. By deferring that question to NAESB, it makes it very difficult for market participants to evaluate whether this standard provides sufficient transparency. The notion of an ATCID document is a positive step. To have a single document with a comprehensive list of assumptions represents a substantial improvement over the status quo. However, the utility of this document, is difficult to evaluate if it is not yet determined which parties will have access to the document. Furthermore, while flexibility is necessary in order to create a standard with applicability across many jurisdictions, allowing undue flexibility as long as assumptions are captured in the ATCID cannot assure market participants of a sufficient degree of standardization. While TSPs are presumably expected to specify this in their CBMID, it should not be left to individual TSPs to determine that when CBM is requested beyond the existing capability of the system, such requests cannot take precedence over rollover rights previously granted to transmission customers.
5Conectiv Energy Supply, Inc.Richard K. Douglass Negative
5Constellation Generation GroupMichael F. Gildea Abstain
5Detroit Edison CompanyRonald W. Bauer Affirmative
5Duke Energy Robert Smith Abstain
5Electric Power Supply AssociationJack R. Cashin Negative Greater transparency is required for the CBMID. This can be achieved through the use of a single document with a comprehensive list of assumptions that improves the status quo. The document should be accessible by all market participants to ensure its utility. The document needs to be flexible enough to have applicability across jurisdictions so that assumptions are captured in the CBMID but not in a manner that undermines market participants having sufficient standardization. While TSPs are presumably expected to specify this in their CBMID, it should not be left to individual TSPs to determine that when CBM is requested beyond the existing capability of the system, such requests cannot take precedence over rollover rights previously granted to transmission customers.
5Entegra Power Group, LLCKenneth Parker Abstain
5FirstEnergy SolutionsKenneth Dresner Negative FirstEnergy Corp. (FE) appreciates the hard work put forth by NERC’s ATC Standard Drafting Team. We offer the following general comments in addition to our specific standard comments presented below. CBM & TRM – MARKET AREAS: FE supports the drafting team’s approach of three ATC methodologies presented in MOD-028, MOD-029 and MOD-030 to account for differences in calculating ATC in various geographic areas of the bulk electric system. However, the use of a single standard methodology for CBM and TRM as currently written does not meet the needs for entities operating within a market area such as MISO, PJM etc. FE suggests that various requirements in the proposed standards that are currently applicable to the TP and TOP are actually handled by the RTO and within a market area would more appropriately be assigned to the Planning Coordinator (PC) and Reliability Coordinator (RC), respectively. This change would allow the proposed standards for CBM and TRM to be used largely “as is” within both market and non-market areas as the PC and RC would be appropriate in both. Our comments below on specific MOD standards elaborate on this point and provide examples where we feel the applicability is inappropriately assigned to TP or TOP responsible entities within a transmission market construct. DECISION TO BALLOT: While the MOD standards presented are improving in content FE believes the standards should have been issued for one more comment period prior to ballot per the NERC Standard Development Procedures (SDP). In many cases this is only the 2nd draft version being reviewed by industry. The objective during the “Solicit Public Comments on Draft Standard (Step 6)” of the NERC SDP is to “Receive stakeholder inputs on the draft standard for the purpose of assessing consensus on the draft standard, and modifying the draft standard as needed to improve consensus.” Based on the 200+ pages of comments of the prior draft version it is hard to conclude that the industry was near consensus. Additionally, per the SDP, now that the standards have gone to First Ballot (Step 9), the standard drafting team is not permitted to make any changes to the standards based on comments received during this First Ballot. The drafting team will now be required to rely on their responses to industry feedback to try and improve consensus during a re-circulation ballot. FE has concerns with the consequences of this decision with regard to the integrity of the standard development process and substantive registered entity perspectives. FirstEnergy Corp. (FE) appreciates the hard work put forth by NERC’s ATC Standard Drafting Team. However, at this time, FE is voting Negative to this standard with the following comments and suggestions: The Planning Coordinator (PC) should replace the Transmission Planner (TP) as the applicable entity. The requirements in R5 and R7 should be the ultimate responsibility of the PC who works with his associated TP to obtain the necessary information. Per the NERC functional model, the PC “coordinates and collects data for system modeling from the Transmission Planner…” and “coordinates total transfer capability with Transmission Planners…”. This standard is too prescriptive with the detail into how CBM should be calculated across all interconnections and does not take into account all the different calculation methods currently used by various entities in the industry. It is suggested that the standard be more general and that some of the information contained is better suited with a guideline document for calculating CBM.
5Florida Municipal Power AgencyDouglas Keegan Negative We believe this standard needs an additional commenting period.
5Florida Power & Light Co.Robert A. Birch
5Great River EnergyCynthia E Sulzer Negative
5JEADonald Gilbert Abstain
5Lincoln Electric SystemDennis Florom Negative LES agrees with the PJM and MISO recommendation that the standard needs an additional commenting period.
5Louisville Gas and Electric Co.Charlie Martin Negative
5New York Power AuthorityRichard J. Ardolino Negative
5North Carolina Municipal Power Agency #1Matthew Schull
5PPL Generation LLCMark A. Heimbach Abstain
5Progress Energy CarolinasWayne Lewis Negative
5PSEG Power LLCThomas Piascik Negative PSEG Power LLC votes no for the reasons expressed in PJM’s comments.
5Salt River ProjectGlen Reeves Affirmative
5Seminole Electric Cooperative, Inc.Brenda K. Atkins Affirmative
5Southern Company Services, Inc.Roger D. Green Affirmative
5Tampa Electric Co.Frank L Busot Affirmative
5Tenaska, Inc.Scott M. Helyer Negative
5Wisconsin Electric Power Co.Linda Horn Negative GCIR definition - We are uncomfortable with the definition of GCIR, especially with no guidance on the determination or use of this quantity. Additionally it is not specified whether this is a maximum or average over the period in question. PRSG definition - The definition states that this is an agreement to jointly meet a resource adequacy requirement, there are some PRSG's that are just doing a "joint study" to determine a requirement but how they meet that requirement may be unique to the LSE. R4.1.2 - The determination of the CBM seems to be disconnected from the current resource adequacy methodology processes that are being used in most RTO's. I.e. a difference in models could induce inconsistencies in the CBM that is actually available and the reserve margins identified in the resource adequacy studies. R4.3 - It is difficult to tell whether the process is a "first come first served" process or whether all CBM requests are evaluated on a common basis. R7 - There should be a consideration to providing these studies to LSE's to assist in coordination of methodologies etc. Measures, M3 - The words "that wants CBM" could be better stated as "is requesting CBM to support the calculated reserve margin"
6AEP MarketingEdward P. Cox Abstain
6Barry Green Consulting Inc.Barry Green Negative Transparency: The former NERC standard for ATC required only that TSPs have and publish their methodology for calculation of ATC. Such a standard has clearly been rejected by FERC, instead opting for much greater transparency. However, we note that amongst the redlined changes in the version of MOD-004 that is being balloted, the word “transparency” has been deleted from the purpose. We also note that the standartd requires that sufficient data will be exchanged to allow for validation of the ATC calculation but in response to EPSA and many others it is clear that NERC will not mandate what if any of this data will be shared with market participants. By deferring that question to NAESB, it makes it very difficult for market participants to evaluate whether this standard provides sufficient transparency. The notion of a CBMID document is a positive step. To have a single document with a comprehensive list of assumptions represents a substantial improvement over the status quo. However, the utility of this document, is difficult to evaluate if it is not yet determined which parties will have access to the document. Furthermore, while flexibility is necessary in order to create a standard with applicability across many jurisdictions, allowing undue flexibility as long as assumptions are captured in the CBMID cannot assure market participants of a sufficient degree of standardization. In addition, while TSPs are presumably expected to specify this in their CBMID, it should not be left to individual TSPs to determine that when CBM is requested beyond the existing capability of the system, such requests cannot take precedence over rollover rights previously granted to transmission customers.
6Bonneville Power AdministrationBrenda S. Anderson Affirmative The purpose statement for MOD-004 should be expanded, to describe the timeframe for which CBM is to be activated so as not to conflict with TRM, to include a statement that “CBM is to be scheduled by the Energy Deficient Entity experiencing a declared NERC Energy Emergency Alert (EEA) 2 or higher only in the hour following a generation forced outage event."
6Calpine Energy ServicesAngela Easton Negative
6Consolidated Edison Co. of New YorkNickesha P Carrol Negative PSRG is not an entity defined in the NERC functional Model.
6Constellation Energy Commodities GroupDonald Schopp Abstain
6Coral Power Corp.Paul Benjamin Kerr Negative
6Dominion Resources, Inc.Louis S Slade Negative Support comments provided by NPCC and PJM
6Entergy Services, Inc.William Franklin Affirmative
6Exelon Power TeamPulin Shah Negative
6FirstEnergy SolutionsMark S Travaglianti Negative FirstEnergy Corp. (FE) appreciates the hard work put forth by NERC’s ATC Standard Drafting Team. However, at this time, FE is voting Negative to this standard with the following comments and suggestions: The Planning Coordinator (PC) should replace the Transmission Planner (TP) as the applicable entity. The requirements in R5 and R7 should be the ultimate responsibility of the PC who works with his associated TP to obtain the necessary information. Per the NERC functional model, the PC “coordinates and collects data for system modeling from the Transmission Planner…” and “coordinates total transfer capability with Transmission Planners…”. This standard is too prescriptive with the detail into how CBM should be calculated across all interconnections and does not take into account all the different calculation methods currently used by various entities in the industry. It is suggested that the standard be more general and that some of the information contained is better suited with a guideline document for calculating CBM.
6Florida Municipal Power AgencyRobert C. Williams
6Great River EnergyDonna Stephenson Negative
6Lincoln Electric SystemEric Ruskamp Negative LES agrees with the PJM and MISO recommendation that the standard needs an additional commenting period.
6Louisville Gas and Electric Co.Daryn Barker Negative
6MidAmerican Energy Co.Dennis Kimm Affirmative Although this standard leaves much to be desired, it is better than the current standard. I hope NERC continues to work towards consistency in the arena of CBM.
6New York Power AuthorityThomas Papadopoulos Negative
6PP&L, Inc.Thomas Hyzinski Abstain
6PSEG Energy Resources & Trade LLCJames D. Hebson Negative PSEG Energy Resources & Trade votes NO for the reasons expressed in PJM's ballot.
6Public Utility District No. 1 of Chelan CountyHugh A. Owen
6Sacramento Municipal Utility DistrictRobert Schwermann Affirmative
6Salt River ProjectMike Hummel Affirmative
6Santee CooperSuzanne Ritter Negative The drafting team's response to Entergy regarding MOD-004-1 Requirement 8 implies that this standard would require a Transmisson Service Provider to furnish CBM to any LSE or "entity" that never requested or funded CBM. Another unintended consequence of Requirement 8 is that entities (some that may already be irresponsibly under-resourced) may furhter reduce their installed capacity investments once they learn they can free ride on their neighbors' CBM.
6South Carolina Electric & Gas Co.John E. Folsom, Jr. Abstain
7Metropolitan Water District of Southern CaliforniaErnest Hahn Abstain
8JDRJC AssociatesJim D. Cyrulewski Negative
8OtherMichehl R. Gent
9California Energy CommissionWilliam Mitchell Chamberlain Affirmative
9Commonwealth of Massachusetts Department of Public UtilitiesDonald E. Nelson Negative Massachustts DPU found problems with the applicability section as it pertains to the planned resource sharing group. Reguirement 1.1 adds this concept of an entity called the Planned Resource Sharing Group. This entity is not defined and is not currently in the latest approved version of the NERC Functional Model (v.3). Adding this entity raises issues for registration and compliance. Requirements have been introduced for the first time in this version. None of these revisions have yet been circulated for comment. New requirements should not be introduced in the final version of a standard without affording the industry some opportunity to comment. This appears to bypass approved NERC RS process.
9National Association of Regulatory Utility CommissionersDiane J. Barney Negative Due to the extensive revisions in the final draft, industry input should have been solicited before setting this revised standard for a vote.
9Public Utilities Commission of OhioKlaus Lambeck Abstain
9Utah Public Service CommissionRic Campbell Affirmative
9Wyoming Public Service CommissionSteve Oxley Affirmative Should not prevent the inclusion of intermittent resources if they exhibit sufficient diversity and can be successfully integrated.
10Electric Reliability Council of Texas, Inc.Kent Saathoff Affirmative
10Midwest Reliability OrganizationLarry Brusseau Negative The MRO agrees with the PJM and MISO recommendation that the standard needs an additional commenting period.
10New York State Reliability CouncilAlan Adamson Negative
10Northeast Power Coordinating Council, Inc.Edward A Schwerdt Negative A new entity, a Planned Resource Sharing Group, that is not identified in the functional model, is included. A re-posting of the standard is recommended to allow for industry comments.
10ReliabilityFirst CorporationJacquie Smith
10Western Electricity Coordinating CouncilLouise McCarren Affirmative