Standard TOP Operations Planning
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- Owen Moore
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1 A. Introduction 1. Title: 2. Number: TOP Purpose: To ensure that Transmission Operators and Balancing Authorities have plans for operating within specified limits. 4. Applicability: 4.1. Transmission Operator 4.2. Balancing Authority 5. Effective Date: See Implementation Plan. 6. Background: See Project project page. B. Requirements and Measures R1. Each Transmission Operator shall have an Operational Analysis that will allow it to assess whether its planned operations for the next day within its Transmission Operator Area will exceed any of its System Operating Limits (SOLs). [Violation Risk Factor: Medium] [Time Horizon: ] M1. Each Transmission Operator shall have evidence of a completed Operational Analysis. Such evidence could include but is not limited to dated power flow study results. R2. Each Transmission Operator shall have an Operating Plan(s) for next-day operations to address potential System Operating Limit (SOL) exceedances identified as a result of its Operational Analysis as required in Requirement R1. [Violation Risk Factor: Medium] [Time Horizon: ] M2. Each Transmission Operator shall have evidence that it has an Operating Plan to address potential System Operating Limits (SOLs) exceedances identified as a result of the Operational Analysis performed in Requirement R1. Such evidence could include but it is not limited to plans for precluding operating in excess of each SOL that was identified as a result of the Operational Analysis. R3. Each Transmission Operator shall notify entities identified in the Operating Plan(s) cited in Requirement R2 as to their role in those [Violation Risk Factor: Medium] [Time Horizon: ] M3. Each Transmission Operator shall have evidence that it notified entities identified in the Operating Plan(s) cited in Requirement R2 as to their role in the Such evidence could include but is not limited to dated operator logs, or records. Page 1 of 10
2 R4. Each Balancing Authority shall have an Operating Plan(s) for the next-day that addresses: [Violation Risk Factor: Medium] [Time Horizon: ] 4.1 Expected generation resource commitment and dispatch 4.2 Interchange scheduling 4.3 Demand patterns 4.4 Capacity and energy reserve requirements, including deliverability capability M4. Each Balancing Authority shall have evidence that it has developed a plan to operate within the criteria identified. Such evidence could include but is not limited to dated operator logs or records. R5. Each Balancing Authority shall notify entities identified in the Operating Plan(s) cited in Requirement R4 as to their role in those [Violation Risk Factor: Medium] [Time Horizon: ] M5. Each Balancing Authority shall have evidence that it notified entities identified in the plan(s) cited in Requirement R4 as to their role in the Such evidence could include but is not limited to dated operator logs or records. R6. Each Transmission Operator shall provide its Operating Plan(s) for next-day operations identified in Requirement R2 to its Reliability Coordinator. [Violation Risk Factor: Medium] [Time Horizon: ] M6. Each Transmission Operator shall have evidence that it provided its Operating Plan(s) for next-day operations identified in Requirement R2 to its Reliability Coordinator. Such evidence could include but is not limited to dated operator logs or records. R7. Each Balancing Authority shall provide its Operating Plan(s) for next-day operations identified in Requirement R4 to its Reliability Coordinator. [Violation Risk Factor: Medium] [Time Horizon: ] M7. Each Balancing Authority shall have evidence that it provided its Operating Plan(s) for next-day operations identified in Requirement R4 to its Reliability Coordinator. Such evidence could include but is not limited to dated operator logs or records. Page 2 of 10
3 C. Compliance 1. Compliance Monitoring Process 1.1. Compliance Enforcement Authority As defined in the NERC Rules of Procedure, Compliance Enforcement Authority (CEA) means NERC or the Regional Entity in their respective roles of monitoring and enforcing compliance with the NERC Reliability Standards Compliance Monitoring and Assessment Processes As defined in the NERC Rules of Procedure, Compliance Monitoring and Assessment Processes refers to the identification of the processes that will be used to evaluate data or information for the purpose of assessing performance or outcomes with the associated reliability standard Data Retention The following evidence retention periods identify the period of time an entity is required to retain specific evidence to demonstrate compliance. For instances where the evidence retention period specified below is shorter than the time since the last audit, the Compliance Enforcement Authority may ask an entity to provide other evidence to show that it was compliant for the full time period since the last audit. Each Transmission Operator and Balancing Authority shall keep data or evidence to show compliance for each applicable Requirement for a rolling 90-calendar days period for analyses, the most recent 90-calendar days for voice recordings, and 12 months for operating logs and records unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation. If a Transmission Operator or Balancing Authority is found non-compliant, it shall keep information related to the non-compliance until found compliant or the time period specified above, whichever is longer. The Compliance Enforcement Authority shall keep the last audit records and all requested and submitted subsequent audit records 1.4. Additional Compliance Information None. Page 3 of 10
4 Table of Compliance Elements R # Time Horizon VRF Violation Severity Levels Lower VSL Moderate VSL High VSL Severe VSL R1 R2 Medium N/A N/A N/A The Transmission have an Operational Analysis allowing it to assess whether its planned operations for the next day within its Transmission Operator Area exceeded any of its System Operating Limits (SOLs). Medium N/A N/A N/A The Transmission have an Operating Plan to address potential System Operating Limit (SOL) exceedances identified as a result of the Operational Analysis performed in Requirement R1. Page 4 of 10
5 R # Time Horizon VRF Violation Severity Levels Lower VSL Moderate VSL High VSL Severe VSL For the Requirement R3 and R5 VSLs only, the intent of the SDT is to start with the Severe VSL first and then to work your way to the left until you find the situation that fits. In this manner, the VSL will not be discriminatory by size of entity. If a small entity has just one affected reliability entity to inform, the intent is that that situation would be a Severe violation. R3 Medium The Transmission notify one impacted entity or 5% or less of the entities, whichever is greater identified in the Operating Plan(s) as to their role in the The Transmission notify two entities or more than 5% and less than or equal to 10% of the impacted entities, whichever is greater, identified in the Operating Plan(s) as to their role in the The Transmission notify three impacted entities or more than 10% and less than or equal to 15% of the entities, whichever is greater, identified in the Operating Plan(s) as to their role in the The Transmission notify four or more entities or more than 15% of the impacted NERC identified in the Operating Plan(s) as to their role in the R4 Medium Authority has an Operating Plan but it does not address one of the criteria in Requirement R4. Authority has an Operating Plan but it does not address two of the criteria in Requirement R4. Authority has an Operating Plan but it does not address three of the criteria in Requirement R4. have an Operating Plan. R5 Medium notify one impacted entity or 5% or less notify two entities or more than 5% and notify three impacted entities or notify four or more entities or more than Page 5 of 10
6 R # Time Horizon VRF Violation Severity Levels Lower VSL Moderate VSL High VSL Severe VSL of the entities, whichever is greater, identified in the Operating Plan(s) as to their role in the less than or equal to 10% of the impacted entities, whichever is greater, identified in the Operating Plan(s) as to their role in the more than 10% and less than or equal to 15% of the entities, whichever is greater, identified in the Operating Plan(s) as to their role in the 15% of the impacted entities identified in the Operating Plan(s) as to their role in the R6 R7 Medium N/A N/A N/A The Transmission provide its Operating Plan(s) for next-day operations as identified in Requirement R2 to its Reliability Coordinator. Medium N/A N/A N/A provide its Operating Plan(s) for next-day operations as identified in Requirement R4 to its Reliability Coordinator. Page 6 of 10
7 D. Regional Variances None. E. Interpretations None. F. Associated Documents Operating Plan - An Operating Plan includes general Operating Processes and specific Operating Procedures. It may be an overview document which provides a prescription for an Operating Plan for the next-day, or it may be a specific plan to address a specific SOL or IROL exceedance identified in the Operational Analysis (OPA). Consistent with the NERC definition, Operating Plans can be general in nature, or they can be specific plans to address specific reliability issues. The use of the term Operating Plan in the revised TOP/IRO standards allows room for both. An Operating Plan references processes and procedures which are available to the System Operator on a daily basis to allow the operator to reliably address conditions which may arise throughout the day. It is valid for tomorrow, the day after, and the day after that. Operating Plans should be augmented by temporary operating guides which outline prevention/mitigation plans for specific situations which are identified day-to-day in an OPA or a Real-time Assessment (RTA). As the definition in the Glossary of Terms states, a restoration plan is an example of an Operating Plan. It contains all the overarching principles that the System Operator needs to work his/her way through the restoration process. It is not a specific document written for a specific blackout scenario but rather a collection of tools consisting of processes, procedures, and automated software systems that are available to the operator to use in restoring the system. An Operating Plan can in turn be looked upon in a similar manner. It does not contain a prescription for the specific set-up for tomorrow but contains a treatment of all the processes, procedures, and automated software systems that are at the operator s disposal. The existence of an Operating Plan, however, does not preclude the need for creating specific action plans for specific SOL or IROL exceedances identified in the OPA. When a Reliability Coordinator performs an OPA, the analysis may reveal instances of possible SOL or IROL exceedances for pre- or post-contingency conditions. In these instances, Reliability Coordinators are expected to ensure that there are plans in place to prevent or mitigate those SOLs or IROLs, should those operating conditions be encountered the next day. The Operating Plan may contain a description of the process by which specific prevention or mitigation plans for day-to-day SOL or IROL exceedances identified in the OPA are handled and communicated. This approach could alleviate any potential administrative burden associated with perceived requirements for continual day-to-day updating of the Operating Plan document for compliance purposes. Page 7 of 10
8 Version History Version Date Action Change Tracking 0 April 1, 2005 Effective Date New 0 August 8, 2005 Removed Proposed from Effective Date Errata 1 August 2, 2006 Adopted by Board of Trustees Revised 2 November 1, 2006 Adopted by Board of Trustees Revised 2 June 14, 2007 Fixed typo in R11., (subject to ) Errata 2a February 10, 2009 Added Appendix 1 Interpretation of R11 approved by BOT on February 10, a December 2, 2009 Interpretation of R11 approved by FERC on December 2, 2009 Interpretation Same Interpretation 2b November 4, 2010 Added Appendix 2 Interpretation of R10 adopted by the Board of Trustees 2b October 20, 2011 FERC Order issued approving the Interpretation of R10 (FERC s Order became effective on October 20, 2011) 2.1b March 8, 2012 Errata adopted by Standards Committee; (Removed unnecessary language from the Effective Date section. Deleted retired sub-requirements from Requirement R14) 2.1b April 11, 2012 Additional errata adopted by Standards Committee; (Deleted language from retired sub-requirement from Measure M7) Errata Errata 2.1b September 13, 2012 FERC approved Errata 3 May 6, 2012 Revisions under Project Revised Page 8 of 10
9 3 May 9, 2012 Adopted by Board of Trustees Revised 4 April 2014 Revisions under Project Revised 4 November 13, 2014 Adopted by NERC Board of Trustees Revisions under Project November 19, 2015 FERC approved TOP Docket No. RM Order No Page 9 of 10
10 Standard TOP Guidelines and Technical Basis Guidelines and Technical Basis Rationale: During development of this standard, text boxes were embedded within the standard to explain the rationale for various parts of the standard. Upon BOT approval, the text from the rationale text boxes was moved to this section. Rationale for Definitions: Changes made to the proposed definitions were made in order to respond to issues raised in NOPR paragraphs 55, 73, and 74 dealing with analysis of SOLs in all time horizons, questions on Protection Systems and Special Protection Systems in NOPR paragraph 78, and recommendations on phase angles from the SW Outage Report (recommendation 27). The intent of such changes is to ensure that Real-time Assessments contain sufficient details to result in an appropriate level of situational awareness. Some examples include: 1) analyzing phase angles which may result in the implementation of an Operating Plan to adjust generation or curtail transactions so that a Transmission facility may be returned to service, or 2) evaluating the impact of a modified Contingency resulting from the status change of a Special Protection Scheme from enabled/in-service to disabled/out-of-service. Rationale for R1: Terms deleted in Requirement R1 as they are now contained in the revised definition of Operational Analysis Rationale for R2: The change to Requirement R2 is in response to NOPR paragraph 42 and in concert with proposed changes made to proposed TOP Rationale for R3: Changes in response to IERP recommendation Rationale for R4 and R5: These Requirements were added to address IERP recommendations Rationale for R6 and R7: Added in response to SW Outage Report recommendation 1 Page 10 of 10
11 Enforcement Dates: Standard TOP United States * FOR INFORMATIONAL PURPOSES ONLY * Standard Requirement Enforcement Date Inactive Date TOP All 04/01/2017 Printed On: January 12, 2017, 05:59 PM
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