Risk-Based Registration. Terry Brinker, Manager, Registration Services, NERC 2014 Standards and Compliance Fall Workshop September 24, 2014

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1 Risk-Based Registration Terry Brinker, Manager, Registration Services, NERC 2014 Standards and Compliance Fall Workshop September 24, 2014

2 Outline Why are we doing this? What is being proposed? Why are we proposing it? Summary 2

3 Background There are ~1,900 registered entities Of these, ~1,200 are owners and operators of the Bulk Electric System (BES) Of these, ~700 are only users of the BES Are we registering the right entities, the entities that are material to reliability? We have an opportunity to right-size the registry 3

4 Background (Continued) Currently, some Reliability Standards already align, or tier requirements to risk There is an opportunity to further promote this concept FAC-003, PRC-023: generally > 200 kv CIP V5: High, Medium and Low Generator Owner (GO)/Transmission Owner (TO) effort A lot of administrative overhead related to proving the negative 4

5 Highlights of RBR Draft Design Proposal A. Remove functions that are commercial in nature Purchasing-Selling Entity (PSE), Load-Serving Entity (LSE), Interchange Authority (IA) B. Raise the Distribution Provider (DP) threshold to 75 MW (directly connected to the Bulk Electric System [BES]) and create a new Underfrequency load shedding (UFLS) Only DP registration C. Align, or tier, standards/requirements to risk for Transmission Operators (TOPs) D. Develop a registration exception process modeled after the BES Exception process. E. Improve the attestation process by allowing a one-time attestation updated as needed 5

6 RBR Benefits Aligns entity registration and compliance burden to its risks and contributions to BES reliability Reduces the industry burden associated with registration, while sustaining continued BES reliability Improves use of NERC, Regional Entity (RE) and registered entity resources Provides feedback to Reliability Standards development to enhance current and future Reliability Standards Increases consistency in registration across the eight REs by developing a common and repeatable approach with improved registration and deactivation procedures 6

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8 Guiding Principles Jurisdiction includes users, owners and operators of the Bulk- Power System (BPS) For owners and operators: BES Definition is the guiding principle for registration Entities that own (and maintain) or operate BES Facilities are candidates for registration as owners or operators (TO/TOP, GO/Generator Operator [GOP]) For users of the BES: material use is a guiding principle for registration 8

9 Owners and Operators Improve alignment with BES Definition in Registry Criteria Use of the term Facility From the NERC Glossary: A set of electrical equipment that operates as a single Bulk Electric System Element Changes in Part II allows deletion of Part III of the Registry Criteria related to a TO, TOP, GO, GOP Proposed Registration Criteria TO: The entity that owns and maintains transmission Facilities TOP: The entity responsible for the reliability of its local transmission system and operates or directs the operations of the transmission Facilities GO: Entity that owns and maintains generating unitsfacility(ies) GOP: The entity that operates generating unit(s)facility(ies) 9

10 Users: Distribution Provider (DP) Concepts: Load is even more dispersed than dispersed resources/power plants The use of the BES by dispersed load is believed to be equivalently impactful to reliability as use of the BES by dispersed resources (and possibly less so) Proposed revisions in the DP registration criteria parallels GO/GOP criteria for dispersed resources, except for o Necessary protection: UFLS, Undervoltage load shedding (UVLS), Special Protection System (SPS), BES Protection o Necessary participation in restoration plan e.g., cranking path o Necessary provision of nuclear plant interface requirements 10

11 Users: DP Proposal Proposed Distribution Provider criteria: DP system that is directly connected to the BES and that serves >75 MW of peak load; or DP that is responsible for providing services related to Nuclear Plant Interface Requirements pursuant to an agreement executed pursuant to NUC 001; or DP with field switching personnel identified as performing unique tasks associated with the TOs restoration plan that are outside of their normal tasks; or DP is the responsible entity that owns, controls, or operates part of any of the following Protection Systems or programs designed, installed, and operated for the protection of the BES: o a required UVLS program o a required SPS o a required transmission Protection System 11

12 Users: DP Proposal (Cont d) Proposed UFLS Only Distribution Provider registration criteria: Does not meet any of the other registration criteria for a DP; and Is the responsible entity that owns, controls, or operates UFLS Protection System(s) needed to implement a required UFLS Program designed for the protection of the BES. UFLS Only DPs are subject only to the PRC Reliability Standard (as modified from time to time) under the DP applicability and any Reliability Standards that specifically reference UFLS-Only DPs in the applicability section. Other standards applicable to DPs are not applicable to UFLS Only DPs. 12

13 Users: DP - Testing the Concepts Evaluation of impact of raising DP threshold to 75 MW Evaluation of potential impact to UFLS programs 13

14 Users: Purchasing and Selling Entity Concepts: Purchasing-Selling Entities (PSEs) are commercial in nature Individual transactions are governed by other rules and regulations: North American Energy Standards Board (NAESB), open access transmission tariff (OATT), market rules, contracts There are over 400 PSE-only entities in the registry Proposal: Remove PSE from the registry Test: Are there other standard considerations? 14

15 Users: Interchange Authority Concepts: Interchange Authority (IA) requirements are proposed to be eliminated from the Interchange standards in the revision filed at FERC Is IA actually a user, or is it an administrative function? Proposal: Remove IA from the registry Test: Evaluate if remaining requirements of the IA are covered by the Balancing Authority (BA) function and/or by NAESB standards 15

16 Users: Load Serving Entity Concepts: The Load Serving Entity (LSE) function is commercial in nature An LSE is not required to own any wires or distribution equipment Activities assigned to the LSE in the standards may be better assigned to a different function DPs may be registered as LSEs in certain cases already under the criteria Proposal: Remove LSE from the registry Test: Ensure all requirements to the LSE are covered by another function. Evaluate if remaining requirements are covered by the by NAESB standards or other agreements. 16

17 Aligning, or Tiering, Requirements to Risks Concepts Many standards adjust requirements to risk: o FAC-003, PRC-023: generally > 200 kv o CIP v5: High, Medium and Low o GO/TO effort There is more opportunity to do so in Risk-Based Registration (RBR) o Low risk TOP sub-set of applicable standards is the focus in RBR o Dispersed Resources Project may provide a future sub-set for GO/GOP o There is less opportunity for additional tiering of standards applicable to a TO and BA than that already contained within the standards; but the effort for TOPs can be used to inform future efforts for other functions 17

18 Aligning Requirements to Risk: Three Options We have several options to align requirements with risk: Reliability Standards Development Process Case-by-case registration review o Individual entity o Commonly shared characteristics of entities Standards development process is slower, more labor intensive process; but may achieve the highest level of alignment We can obtain the majority of that alignment through the registration process GO/TO effort resulted in sub-set through registration and later changes to Reliability Standards Low risk TOP and UFLS-Only DP build on this experience 18

19 Aligning Requirements to Risk: Proposal, Part 1 Low Risk TOP that meets the registry criteria for a TOP, but has: No interconnected BES generation No Blackstart unit No cranking path Its Load is not used in a neighboring TOP restoration plan to control frequency or voltage within that TOP s System No Facilities that meet PRC Attachment B No Medium Risk assets in accordance with CIP other than a TOP Control Center 19

20 Aligning Requirements to Risk: Proposal, Part 2 A Low-Risk TOP is proposed to have a reduced set of requirements to comply with, and is proposed to not be subject to: EOP on System Restoration Plan EOP on Loss of Control Center Functionality, specifically R4, R6 and R7 PER on operator certification PER on operator training, rather than an annual requirement, is proposed to be adjusted to a biennial requirement. TOP 004 2, R4 on unknown states TOP 008 1, R4 on causes of System Operating Limit violations VAR on voltage schedule 20

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22 Registration Exception Process: Modeled after the BES Exception Process The BES Definition is designed around a series of bright-lines with an Exception process to either remove Elements from the BES or include Elements in the BES based on the Element s materiality to BES reliability Similarly, the Registration Criteria is proposed to be a series of bright-lines (discussed in prior slides) accompanied by an Exception process to either de-activate or reduce compliance responsibilities or include compliance responsibilities based on the materiality of the entity on reliability A new Materiality test is proposed for above-the-line and below-the line registration reviews 22

23 Centralized Review Process Composed of a NERC lead with Regional Entity participants To provide a basis for NERC and regional consistency To vet threshold applications, materiality, or Reliability Standard requirement applicability issues Decisions will be shared throughout the electric reliability organization (ERO) Enterprise and publicly posted on the NERC web site, subject to confidentiality requirements in Section 1500 of NERC rules 23

24 Factors for Materiality Is the entity specifically identified in the emergency operation plans and/or restoration plans of a Reliability Coordinator, BA, GOP or TOP? Will intentional or inadvertent removal of a resource or Element owned or operated by the entity lead to loss of a BES resource or transmission Element of a GOP or TOP? Will intentional or inadvertent removal of a resource or Element owned or operated by the entity lead to an unintended loss of firm BES connected load of a BA or TOP? Can the normal operation, Misoperation or malicious use of the entity s cyber assets cause a detrimental impact on the operational reliability of an associated BA, GOP or TOP? Can the normal operation, Misoperation or malicious use of the entity s Protective Systems cause a detrimental adverse impact on the operational reliability of an associated BA, GOP or TOP, or the automatic load shedding programs of a Planning Coordinator or Transmission Planner (UFLS, UVLS)? 24

25 RBR Overview Flowchart 25

26 Improving the Attestation Process Entity can submit a one-time attestation with updates as needed No need to prove a negative if no reporting changes are required Entity has no SPS, no UVLS, no reportable disturbances, does not provide nuclear plant interface services, has received no directives, etc. The entity has the obligation to report changes The ERO has the opportunity to verify the attestations 26

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28 Summary By removing commercial functions from the registry and aligning the DP threshold to the GOP threshold of 75 MW, from which we expect to reduce the number of registered entities by of upwards of 25 percent By tiering requirements to Low Risk TOPs and UFLS-Only DPs By improving the Attestation process And by developing and implementing a consistently applied registration exception process We expect to significantly improve the efficacy and efficiency of the ERO Enterprise (regions, NERC, entities) by reducing unnecessary burden with immaterial impact to reliability. 28

29 RBR Timeline 29

30 Upcoming Dates Technical Studies supporting or refuting any draft Design proposals are due on September 29, Draft Design and Implementation Plan have been presented to the NERC Board of Trustees (Board) Compliance Committee and the Member Representatives Committee on August 20, Revised Design, Implementation Plan, and Rules of Procedure (ROP) Changes have been posted for comments on August 26th. Final industry comments due early October. Final Design, Implementation Plan, and ROP Changes will be presented to the NERC Board in November. 30

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32 Definition of BES Implementation Tom Burgess, NERC Vice President and Director of Reliability Assessment and Performance Analysis 2014 Standards and Compliance Fall Workshop September 24, 2014

33 BES Definition at a Glance Consistent, uniform way to determine BES assets Effective 7/1/2014 Transition period through 7/2016 ERO enterprise common process and tool for implementation Documents and training readily available BES web page one stop shopping Regional and NERC staff resources available to answer detailed questions and implementation Expect additional refinements and clarifications over time 2

34 What is the Bulk Electric System? The Bulk Power System (established by Section 215 of the FPA) The Bulk Electric System (established by the Core Definition, Inclusions, and Exclusions) Exceptions Exclusions and Inclusions established through procedures Rules of Procedure 3

35 BES Core Definition Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission Elements operated at 100 kv or higher and Real Power and Reactive Power resources connected at 100 kv or higher. This does not include facilities used in the local distribution of electric energy. 4

36 Inclusions Provide additional clarification for the purposes of identifying specific Elements that are included in the BES. I1. BES Transformers I2. Real Power Resources I3. Blackstart Resources I4. Dispersed power producing resources meeting certain criteria I5. Reactive Power Resources 5

37 Exclusions Provide additional clarification for the purposes of identifying specific Elements that may be excluded from the BES. E1. Radial Systems E2. Retail Generation E3. Local Networks E4. Reactive Power Devices installed solely for retail customers 6

38 How to Apply the BES Definition, Inclusions, and Exclusions Consistent methodology outlined in the BES Definition Reference Document Step 1: Core Definition Step 2: Inclusions Step 3: Exclusions STEP 3: EXCLUSIONS should be applied in the following sequence: E2 Retail Generation (supersedes I2 Real Power Resources) E4 Retail Reactive Power Devices (supersedes I5 Reactive Power Resources) E3 Local Networks (does not exclude interconnection facilities or generators) E1 Radial Systems (does not exclude interconnection facilities or generators) 7

39 BES Self Determined Notifications Gives NOTIFICATION to Regional Entities and NERC that proper application of the BES Definition has resulted in An Inclusion (an element not previously considered in the BES is now classified as part of the BES) An Exclusion (an element previously considered in the BES is no longer classified as part of the BES) Review process assures entities implement definition correctly Compliance obligations cease for facilities correctly excluded from BES 24-month implementation period for newly-identified BES Facilities NOT the method for asking for an exception to the definition 8

40 Self-Determination Notification Information Requirements Each notification should at a minimum include the following: Current one-line diagrams highlighting the elements in question For E2 Retail Generation Exclusion Net Capacity Transactional Data (12 months of hourly data) Documentation of standby, back-up and maintenance power service arrangements For E3 Local Network Exclusion Power Flow Transactional Data (24 months of hourly data) 9

41 BES Exception Requests Exceptions to the Rule Used when application of the definition leads to an incorrect answer (excludes something important, or includes something that is not) Must demonstrate that the specific Elements or groups of Elements are (for inclusions) or are not (for exclusions) necessary for the reliable operation of the interconnected transmission system 10

42 Who can Submit an Exception Request? Owner of the Element(s) Regional Entity Entity with Scope of Responsibility for the Element(s) under consideration: Regional Entity Planning Authority Reliability Coordinator Transmission Operator Transmission Planner Balancing Authority 11

43 The Exception Request Process The Main Steps in the Exception Process: Exception Request Submittal Regional Entity (RE) Initial Review Regional Entity Substantive Review and Recommendation NERC Review and Final Decision Up to 75 days Up to 6 months Up to 120 days Submitting Entity prepares Exception Request RE initial screening and applicable entity input RE substantive review and recommendation NERC Panel Review and Decision Appeal of Rejection based on completeness Technical Review Panel input (if applicable) Challenge of NERC Decision (Rule 1703) 12

44 The BESnet Application Centralized, Web-based application Hosted in Tier IV data facility Highly secure, fully redundant User base Registered and Unregistered Entities Regional Entities NERC Single ERO Enterprise approach for all Registered Entities, Regions, and NERC 13

45 The BESNet Application ERO Enterprise Tool One Tool for all Registered Entities, Regions, and NERC One Credential for all Enterprise tools o Standards Balloting System o BESnet Developed tool and business processes collaboratively with Regions Structured Implementation Extensive outreach from NERC and Regions Guidance, FAQs, and other support documents Several Training and Question/Answer sessions Web-based training materials available Staged opening and slow roll approach 14

46 Observations - SDNs Exclusions 57% Inclusions 43% AC Lines 63% Capacitors 11% Reactors 10% Other 16% AC Lines 80% Transformers 16% Majority of Inclusions are AC Lines; Primarily in NPCC Majority of Exclusions are also AC Lines; Primarily in WECC, RF, and NPCC So far, only four elements where Regions believe definition may have been misapplied. Those cases awaiting NERC review. SDNs Elements Other 4% 15

47 Observations - SDNs Exclusions 57% Inclusions 43% Core Definition 65% I5 - Reactive 19% Other 16% E1 - Radial 77% Majority of Inclusions based on Core Definition; Primarily in NPCC Majority of Exclusions based on E1 (Radial Exclusion); Primarily in WECC and NPCC Not meeting I1 15% Other 8% SDNs Elements 16

48 Observations - ERs Exclusions 100% Transmission Lines 56% Transformers 14% Majority of Exception Requests are for Transmission Lines; Primarily in NPCC All 10 submitted ERs are still undergoing Regional review Other 30% ERs Elements 17

49 Lessons Learned Progress and Submittals good quality, at levels expected Talk to your Region Review the FAQ and Guidance Materials Submittals: Group elements into reasonable submissions elements max per ER or SDN Group logically Submittals: Quality one-line diagrams essential Don t assume reviewer knows your system Mark the elements clearly; indicate what applies (Core, E2, I3, etc ) Reference FAQ

50 One-Line Diagram Example SAMPLE 19

51 For Additional Information 20

52 For Additional Information 21

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54 PRC Standards September 16-17, 2014 Stephen Crutchfield NERC Standards

55 Projects Project , DM (PRC-002) Project , UFLS (PRC-006) Project , Stable Power Swings (PRC-026) Project , System Protection Coordination (PRC-027) Project , Special Protection System and Remedial Action Scheme definitions 2

56 Project Disturbance Monitoring (PRC-002-2)

57 Disturbance Monitoring:PRC Revised Requirement R1 by separating it into distinct Parts rather than having the requirement contained in a single sentence. R1. Each Transmission Owner shall: [Violation Risk Factor: Lower ] [Time Horizon: Long-term Planning] Identify BES buses for which sequence of events recording (SER) and fault recording (FR) data is required by using the methodology in PRC-002-2, Attachment 1; 1.2 Notify other owners of BES Elements connected to those BES buses, if any, within 90 calendar days of completion of Part 1.1 that those BES Elements require SER data and/or FR data; 1.3 Re-evaluate all BES buses at least once every five calendar years in accordance with Part 1.1 and notify other owners, if any, in accordance with Part 1.2, and implement the re-evaluated list of BES buses as per the Implementation Plan.

58 Disturbance Monitoring:PRC Revised Requirement R5 similar to revisions in R1 and: Removed references to BES buses and replaced with BES Elements. Eliminated bulleted list in Part which contained commercial considerations such as flowgates now reads Any one BES Element that is part of a stability (angular or voltage) related System Operating Limit (SOL). Clarified the minimum DDR coverage requirement Part 5.2: 5.2 Ensure a minimum DDR coverage, inclusive of those BES Elements identified in Part 5.1, of at least: o One BES Element. o One BES Element per 3,000 MW of its historical peak System Demand. 5

59 Disturbance Monitoring:PRC The following Parts were included in the main text of Requirement R5 and were broken out into distinct Parts: 5.3 Notify all owners of identified BES Elements, within 90-calendar days of completion of Part 5.1, that their respective BES Elements require DDR data when requested. 5.4 Re-evaluate all BES Elements at least once every five calendar years in accordance with Parts 5.1 and 5.2 and notify owners in accordance with Part 5.3, and implement the reevaluated list of BES Elements as per the Implementation Plan. 6

60 Disturbance Monitoring:PRC Revised Requirement R10 to relate to time synchronization of the device clock rather than data. Original language called for time synchronization of SER data within +/- 2 milliseconds. The equipment used to measure the electrical quantities must be time synchronized to ± 2 ms accuracy; however, accuracy of the application of this time stamp and therefore the accuracy of the data itself is not mandated. This is because of inherent delays associated with measuring the electrical quantities and events such as breaker closing, measurement transport delays, algorithm and measurement calculation techniques, etc. 7

61 Disturbance Monitoring:PRC Revised Requirements R6 and R7 to have similar language since the requirements are similar (DDR data) but apply to different entities (TO, GO). Revised several measures to include station drawings and other documentation as evidence. Clarified Requirement R11 that data will be retrievable for the period of 10 calendar days, inclusive of the day the data was recorded. Revised Requirement R12 for TO or GO to restore recording capability or to submit a CAP to the Regional Entity and implement it. Used defined terms System, Transmission and Disturbance. 8

62 Disturbance Monitoring:PRC PRC was posted for a 45-day comment/ballot period May 9-June 25, The DMSDT reviewed the comments received and made significant revisions to the standard. PRC was posted for an additional 45-day comment ballot period September 5 October 21, Ballot runs October 10-21,

63 Project , UFLS (PRC-006-2)

64 UFLS : Background Information Very limited project scope Revise PRC to: address outstanding FERC directive review the standard to determine if any steady state modifications are appropriate (i.e., Paragraph 81 criteria and recommendations of the Independent Expert Review Panel). UFLS team: Subset of existing UVLS team Beneficial because team can ensure consistency and alignment with UVLS standard Otherwise, UFLS project is separate and distinct from UVLS project: Different subject matters (UVLS vs. UFLS) Different project timelines and posting schedules Different project scope (UFLS work limited to FERC directive and steadystate modifications) 11

65 UFLS FERC Directive FERC raised concern that PRC does not specify how soon after an event would an entity need to implement corrections in response to any deficiencies identified in the event assessment under Requirement R11. FERC Order No. 763: Notwithstanding NERC s comments, the Commission is not persuaded that Requirement R9 requires corrective action in accordance with a schedule established by the planning coordinator...accordingly, we direct NERC to make that requirement explicit in future versions of the Reliability Standard. Within 30 days of the effective date of this Final Rule, NERC is directed to submit a compliance filing indicating how it plans to comply with this directive and a deadline for compliance. (Paragraph 48) 12

66 UFLS Proposal to Address FERC Directive Add one new Requirement (R15) Revise two existing Requirements (R9 and R10) to accommodate for new Requirement. 13

67 Proposed Revisions to PRC R9 R10 R15 (new) Each UFLS entity shall provide automatic tripping of Load in accordance with the UFLS program design and schedule for application implementation, including any Corrective Action Plan, as determined by its Planning Coordinator(s) in each Planning Coordinator area in which it owns assets. [VRF: High][Time Horizon: Long-term Planning] Each Transmission Owner shall provide automatic switching of its existing capacitor banks, Transmission Lines, and reactors to control over-voltage as a result of underfrequency load shedding if required by the UFLS program and schedule for application implementation, including any Corrective Action Plan, as determined by the Planning Coordinator(s) in each Planning Coordinator area in which the Transmission Owner owns transmission. [VRF: High][Time Horizon: Long-term Planning] Each Planning Coordinator that conducts a UFLS design assessment under Requirement R4, R5, or R12 and determines that the UFLS program does not meet the performance characteristics in Requirement R3, shall develop a Corrective Action Plan and a schedule for implementation by the UFLS entities within its area. [VRF: High][Time Horizon: Long-term Planning] 15.1 For UFLS design assessments performed under Requirement R4 or R5, the Corrective Action Plan shall be developed within the five-year time frame identified in Requirement R For UFLS design assessments performed under Requirement R12, the Corrective Action Plan shall be developed within the two-year time frame identified in Requirement R12.

68 PRC UFLS July August: UFLS drafting team industry outreach August 21 October 8: 45-day formal comment and ballot period October 20 October 30: 10-day final ballot November: NERC Board of Trustees for Approval 15

69 Project Phase 3 of Relay Loadability: Stable Power Swings (PRC-026-1)

70 Project Background FERC Order No. 733 (dated March 18, 2010) 17 Approved PRC Transmission Relay Loadability Directed NERC to address three other items Project SAR addressed directives in three phases Modification to transmission relay loadability (PRC-023-2) Address generator relay loadability (PRC-025-1) Address relay loadability due to stable power swings (PRC-026-1) Subsequent FERC Order Nos. 733-A and 733-B Responded to industry and NERC concerns Reaffirmed the need for a loadability standard to address power swings Planning Committee endorsed report for drafting standard by Protection System Response to Power Swings, August 2013 (PSRPS Report) Project Project Page

71 Why PRC is Moving Forward Responsibility Address a reliability concern (i.e., tripping during stable power swings) ERO must be responsive to directives Two possible approaches to meet directive(s): 1. Develop requirements applicable to protection systems on all circuits, or 2. Identify the specific circuits on which a power swing may affect protection system operation The PRC approach is consistent with the PSRPS Report Provides definitive criteria for identifying Elements Provides protection system assessment criteria Does not sacrifice protection system dependability and security Equally effective and efficient approach to meet directives 18

72 PRC Draft 1 Issues PSRPS report recommended a standard was not necessary Standard s purpose was perceived as unachievable relays do not trip was revised to relays are expected to not trip January 1, 2003 historical date (removed) Planners only allowed one month to provide identified Elements Revised to each calendar year Requirements Responsibilities not clearly defined between entities Time periods were restrictive and unclear Relay evaluation Requirement overly complicated with multiple activities Application Guidelines Need to include more examples and additional detail 19

73 PRC Draft 2 Applicability Functional Entities: Generator Owners and Transmission Owners o That apply load-responsive protective relays on Elements (Attachment A) Planning Coordinator (has widest-area view) Facilities Bulk Electric System (BES) Elements o Generators, transformers, and transmission lines Changes in draft 2 Reliability Coordinator and Transmission Planners were removed o Stakeholders concerned about potential notification overlap and which criteria should each entity be responsible for performing o Stakeholders affirmed a single source is more practical 20

74 PRC Draft 2 Structure Six Requirements with single activities R1 Element identification by the Planning Coordinator R2 & R3 Element identification by the Transmission Owner and Generator Owner for trips due to power swings R4 Evaluation of load-responsive protective relays for identified Elements by the GO/TO Modification of the Protection System where a relay does not meet the performance criteria o R5 Develop the Corrective Action Plan (CAP) o R6 Implement the CAP Enhanced Application Guidelines Detailed narratives, calculations, and figures Spreadsheet tool posted for stakeholder use 21

75 Project Current Status PRC Relay Performance During Stable Power Swings Posted for 45-day comment through Monday, October 6, 2014 Additional ballot will be held September 26 to October 6, 2014 At See Program Areas, Standards, Reliability Standards Development Next Steps Industry Webinar on September 18, 2014 Click here to register Respond to Draft 2 industry comments o Drafting team will meet October 7-10, 2014 at NERC, Atlanta, GA o Click here to register for in-person or remote attendance Final ballot in October 2014, or additional comment period (if needed) Present to NERC Board of Trustees File by December 31, 2014 to meet regulatory deadline in Order

76 Project , System Protection Coordination (PRC-027-1)

77 System Protection Coordination:PRC The drafting team is correcting the applicable entities to the owners of the Protection Systems rather than the operating entities. PRC-027 applies to Protection Systems installed for the purpose of detecting Faults on BES Elements and isolating the faulted Elements. The Purpose is to coordinate those Protection Systems such that they operate in the intended sequence during Faults. 24

78 System Protection Coordination:PRC Retire Requirements R3 an R4 from PRC : R3. A Generator Operator or Transmission Operator shall coordinate new protective systems and changes as follows. R3.1. Each Generator Operator shall coordinate all new protective systems and all protective system changes with its Transmission Operator and Host Balancing Authority. R3.2. Each Transmission Operator shall coordinate all new protective systems and all protective system changes with neighboring Transmission Operators and Balancing Authorities. R4. Each Transmission Operator shall coordinate Protection Systems on major transmission lines and interconnections with neighboring Generator Operators, Transmission Operators, and Balancing Authorities. 25

79 System Protection Coordination:PRC The draft standard was posted for comment and ballot period that ended on 12/31/13. The standard achieved an approval rating of 65.71%. FERC raised significant concerns on the last posted draft that warranted further discussions with members of FERC staff from the Office of Electric Reliability to obtain input for the drafting team. The drafting team is now preparing to meet to discuss the feedback and suggestions to move the standard forward. 26

80 Project , Special Protection System and Remedial Action Scheme definitions

81 Project Scope Phase 1 The SDT will revise the NERC Glossary of Terms definition for a Special Protection System (SPS) or Remedial Action Scheme (RAS) Phase 2 The SDT will address the six existing SPS-related standards: PRC Special Protection System Review Procedure PRC Special Protection System Database PRC Special Protection System Assessment PRC Special Protection System Data and Documentation PRC Special Protection System Misoperations PRC Special Protection System Maintenance and Testing 28

82 Existing SPS/RAS Definition An automatic protection system designed to detect abnormal or predetermined system conditions, and take corrective actions other than and/or in addition to the isolation of faulted components to maintain system reliability. Such action may include changes in demand, generation (MW and Mvar), or system configuration to maintain system stability, acceptable voltage, or power flows. An SPS does not include (a) underfrequency or undervoltage load shedding or (b) fault conditions that must be isolated or (c) out-of-step relaying (not designed as an integral part of an SPS). Also called Remedial Action Scheme. 29

83 Why revise the definition? Provides the clarity and specificity needed to consistently identify what equipment or schemes qualify as RAS Promotes the consistent application of the RAS related NERC Reliability Standards 30

84 Definition Development The SDT is recommending to retain the term Remedial Action Scheme (RAS) and retire the term Special Protection System (SPS). The reasons for RAS: A single term will promote consistency RAS is a more descriptive term for the installation Eliminates the confusion associated with the three defined terms Special Protection System, Protection System, and System 31

85 SDT Proposed RAS Definition (Slide 1 of 4) Remedial Action Scheme (RAS) A scheme designed to detect predetermined System conditions and automatically take corrective actions that may include, but are not limited to, adjusting or tripping generation (MW and Mvar), tripping load, or reconfiguring a System(s). RAS accomplish objectives such as: Meet requirements identified in the NERC Reliability Standards; Maintain Bulk Electric System (BES) stability; Maintain acceptable BES voltages; Maintain acceptable BES power flows; Limit the impact of Cascading or extreme events. 32

86 SDT Proposed RAS Definition (Slide 2 of 4) The following do not individually constitute a RAS: a. Protection Systems installed for the purpose of detecting Faults on BES Elements and isolating the faulted Elements b. Schemes for automatic underfrequency load shedding (UFLS) and automatic undervoltage load shedding (UVLS) comprised of only distributed relays c. Out-of-step tripping and power swing blocking d. Automatic Reclosing schemes e. Schemes applied on an Element for non-fault conditions such as, but not limited to, generator loss-of-field, transformer top-oil temperature, overvoltage, or overload to protect the Element against damage by removing it from service 33

87 SDT Proposed RAS Definition (Slide 3 of 4) f. Controllers that switch or regulate one or more of the following: series or shunt reactive devices, flexible alternating current transmission system (FACTS) devices, phase-shifting transformers, variable-frequency transformers, or tap-changing transformers; and, that are located at and monitor quantities solely at the same station as the Element being switched or regulated g. FACTS controllers that remotely switch static shunt reactive devices located at other stations to regulate the output of a single FACTS device h. Schemes or controllers that remotely switch shunt reactors and shunt capacitors for voltage regulation that would otherwise be manually switched i. Schemes that automatically de-energize a line for a non-fault operation when one end of the line is open j. Schemes that provide anti-islanding protection (e.g., protect load from effects of being isolated with generation that may not be capable of maintaining acceptable frequency and voltage) 34

88 SDT Proposed RAS Definition (Slide 4 of 4) k. Automatic sequences that proceed when manually initiated solely by a System Operator l. Modulation of HVdc or FACTS via supplementary controls, such as angle damping or frequency damping applied to damp local or inter-area oscillations m. Sub- synchronous resonance (SSR) protection schemes that directly detect sub-synchronous quantities (e.g., currents or torsional oscillations) n. Generator controls such as, but not limited to, automatic generation control (AGC), generation excitation [e.g. automatic voltage regulation (AVR) and power system stabilizers (PSS)], fast valving, and speed governing 35

89 Definition Timeline The timeline for the development process is as follows: Developed the SAR 02/14 Posted SAR (30-day comment period) 02/18 03/19 Posted straw-man definition (30-day comment period) 03/11 04/09 Developed definition and associated documents 04/15 05/30 First posting 06/11 7/25 o 58.88% approval Second posting 08/29 10/14 Post for final ballot 10/31 11/10 Present to NERC Board of Trustees for adoption 11/13 File with applicable regulatory authorities for approval 12/15 36

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91 Project Dispersed Generation Resources Standard Drafting Team (DGR SDT) Tony Jankowski, Chair DGR-SDT 2014 Standards and Compliance Fall Workshop September 24, 2014

92 Project Overview Standard Authorization Request (SAR) posted for formal comment on November 20, 2013 FERC approved the Bulk Electric System (BES) Phase 2 Definition on March 20, 2014 The order recognizes this project Address all Generation Owner (GO)/Generator Operator (GOP) standards and some other functions that rely on GO/GOP data Currently enforceable and pending regulatory approval Coordinate activity among active standard drafting teams (SDTs) and committees 2

93 Project Overview (Cont d) White Paper posted on April 2014 April 28, 2014: Industry Webinar May 5, 2014: White Paper comments received Industry generally approves of direction of Dispersed Generation Resources (DGR) SDT 3

94 Project Timeline June 2014: Initial high-priority standards posted for comment and ballot July 5, 2014: Industry Webinar Sept 5, 2014: PRC-005-2,3x - Final Ballot 85 percent quorum; 95 percent pass October 2014: PRC-004, VAR-002 Ballot November 2014 targeted for NERC Board of Trustees (Board) approval of high-priority standards First Quarter 2015: Anticipated project completion Medium priority standards target Board approval in February

95 Concepts Applied to the Standards BES Definition Phase 2 The BES definition includes the following inclusion criterion addressing dispersed generation resources: o I4. Dispersed power producing resources that aggregate to a total capacity greater than 75 MVA (gross nameplate rating), and that are connected through a system designed primarily for delivering such capacity to a common point of connection at a voltage of 100 kv or above. Thus, the facilities designated as BES are: a) The individual resources, and b) The system designed primarily for delivering capacity from the point where those resources aggregate to greater than 75 MVA to a common point of connection at a voltage of 100 kv or above. 5

96 Concepts Applied to the Standards Intent is to not modify content of requirements Focus on applicability unique to dispersed generation resources Applicability options As stated in BES Definition At point of aggregation >=75MVA At connection to Grid, aggregate Facility level Necessary for reliability Technical justification for departure from status quo Standards grouping/buckets by timeframe or functionality and priority 6

97 White Paper White Paper posted on April 4, 2014 Living evolving document Direction of the SDT Technical consideration of the unique characteristics of dispersed generation Prioritization of standards to address o High, Medium, and Low Present options for potential modifications to the standards o Focus on applicability o Develop technical analyses related to possible recommendations Elicit feedback from industry Assist SDT in coordination efforts 7

98 Standards Reviewed and Priority Groupings Appendix A overview: Approval status of the standards which include: Subject to Enforcement Subject to Future Enforcement Filed and Pending Regulatory Approval Pending Regulatory Filing Designated for Retirement (Two standards MOD and MOD officially listed as Filed and Pending Regulatory Approval but will be superseded by MOD-025-2) Proposed for Remand (Four standards IRO-001-3, IRO-005-4, TOP-002-3, and TOP officially listed as Filed and Pending Regulatory Approval but, as of April 10, 2014, proposed to be remanded) Project Revisions to TOP/IRO Reliability Standards 8

99 Standards Reviewed and Priority Groupings Three Categories for Dispersed Generation Resources: The existing standard language is appropriate when applied to dispersed generating resources and does not need to be addressed; The existing standard language is appropriate when applied to dispersed generating resources but additional NERC guidance documentation is needed to clarify either how to implement the requirements for dispersed generating resources or how to demonstrate compliance for such resources; and The existing standard language needs to be modified in order to account for the unique characteristics of dispersed generation resources. This could be accomplished through the applicability section of the standard in most cases or, if required, through changes to the individual requirements. However, please note that any recommended changes to requirements are limited to changes in the applicability of the subject requirement and will not include technical changes to any requirement. 9

100 High Priority Standards PRC-004 (DGR versions PRC a(X) and PRC-004-3(X)) Posted on July 10, 2014 Comments due on October 22, 2014 PRC-005 (DGR versions PRC-005-2(X), PRC-005-3(X), and PRC- 005-X(X)) Posted on June 12, 2014 Passed final ballot on September 5, 2014 (85 percent quorum; 95 percent pass) VAR-002 (DGR versions VAR-002-2b(X) and VAR-002-4) Posted on June 12, 2014 Comments due on October 16, 2014 Target Board approval date is November

101 Medium-Priority Standards The DGR SDT initially identified 14 medium-priority standards: EOP FAC MOD MOD MOD MOD PRC PRC PRC PRC TOP-001-1a TOP b TOP TOP

102 Medium-Priority Standards The DGR SDT recommends modifying the applicability of five medium-priority standards: PRC PRC PRC TOP b* TOP-003-1* o *Action deferred until substantive revisions approved by industry Target Board approval date is February

103 Medium-Priority Standards The DGR SDT intends to provide guidance on two mediumpriority standards: FAC PRC The DGR SDT concluded that no action is necessary on seven standards initially classified as medium-priority: EOP MOD MOD MOD MOD TOP-001-1a TOP

104 Lower-Priority Standards The DGR SDT has identified four low-priority standards: BAL-001-TRE-1 PRC-004-WECC-1 PRC-006-NPCC-1 PRC-006-SERC-01 Recommended applicability changes deferred to the regions for consideration 14

105 15

106 Project Revisions to the TOP/IRO Reliability Standards 2014 Standards and Compliance Fall Workshop September 24, 2014

107 Agenda Background Standard Drafting Team (SDT) Roster Project History and Schedule Project Inputs Impacted Standards Communication Plan Project Technical Summary Definitions IRO and TOP Standards Data Retention, Violation Risk Factors (VRFs), and Violation Severity Levels (VSLs) System Operating Limit (SOL) Exceedance Whitepaper Reliability Standard Audit Worksheets (RSAWs) Next Steps Questions and Answers 2

108 3

109 SDT Roster Dave Souder, PJM, Chair Andy Pankratz, FPL, Vice Chair David Bueche, CenterPoint Jim Case, Entergy Allen Klassen, Westar Bruce Larsen, WE Energies Jason Marshall, ACES Bert Peters, Arizona Public Service Robert Rhodes, SPP Kyle Russell, IESO Eric Senkowicz, FRCC Kevin Sherd, MISO Industry Observers FERC Observers 4

110 Project History and Schedule April 16, 2013: Projects and submitted November 21, 2013: Both projects proposed for remand December 20, 2013: NERC asked FERC to postpone remand January 14, 2014: FERC agreed to postpone until January 31, 2015 February 12, 2014: Project started May 19, 2014 July 2, 2014: First posting August 6, 2014 September 19, 2014: Second Posting October 2014: Final ballot November, 2014: Present to NERC Board of Trustees (Board) for approval File with FERC ASAP after Board approval 5

111 Project Inputs Projects and Standard Authorization Requests (SARs) Directives and Issues FERC Notice of Proposed Rulemaking (NOPR) Independent Experts Report SW Outage Report Operating Committee Executive Committee Memo IRO Five-Year Review Technical Conferences Industry Webinars (June 12, August 12, and September 9) First and Second Posting Comments 6

112 Impacted Standards Revised Standards (will retire all previous versions): TOP-001-3, TOP-002-4, TOP IRO-001-4, IRO-002-4, IRO-008-2, IRO-010-2, IRO Retired Standards: TOP-004-2, TOP-005-2a, TOP-006-3, TOP-007-0, TOP IRO-003-2, IRO-004-2, IRO a, IRO-015-1, IRO New Standard: IRO-017 7

113 Communication Plan 8 ERCOT NERC Standards Review Sub-Committee FRCC Operating Reliability Subcommittee & Operating Committee ISO/RTO Council Standards Review Committee MISO Reliability Subcommittee MRO NERC Standards Review Forum NERC Operating Committee, Operating Reliability Subcommittee, & Planning Committee NPCC Operating Committee, Task Force Coordinated Operations PJM Reliability Standards and Compliance Subcommittee RFC Reliability Committee SERC Operating Committee Review Group SPP Operating Reliability Working Group (ORWG) WECC Operating Committee Industry Webinars (June 12, August 12, and September 9) NERC Standards and Compliance Workshop

114 9

115 Technical Summary - Issues Replaced Reliability Directive with Operating Instruction consistent with proposed COM Clean-up of applicability: Transmission Operator/Balancing Authority responsibilities in TOP standards, Reliability Coordinator responsibilities in IRO standards Elimination of redundant requirements 10

116 Technical Summary - Definitions Clarified and strengthened definitions of Operational Planning Analysis and Realtime Assessment Real-time Assessment (RTA): An evaluation of system conditions using Real-time data to assess existing (pre-contingency) and potential (post-contingency) operating conditions. The assessment shall reflect applicable inputs including, but not limited to: load, generation output levels, known Protection System and Special Protection System status or degradation, Transmission outages, generator outages, Interchange, Facility Ratings, and identified phase angle and equipment limitations. (Real-time Assessment may be provided through internal systems or through third-party services.) Operational Planning Analysis (OPA): An evaluation of projected system conditions to assess anticipated (pre-contingency) and potential (post-contingency) conditions for next-day operations. The evaluation shall reflect applicable inputs including, but not limited to, load forecasts; generation output levels; Interchange; known Protection System and Special Protection System status or degradation; Transmission outages; generator outages; Facility Ratings; and identified phase angle and equipment limitations. (Operational Planning Analysis may be provided through internal systems or through third-party services.) 11

117 Technical Summary IRO/TOP IRO R4 and TOP Real-Time Assessment Requirement R5 and R13 changed performed a Real-time Assessment to ensure that a Real-time Assessment is performed Allows flexibility for situations where other entities may perform Real-time Assessment under a Loss of Control Center Functionality scenario as defined within that entity s Operating Plan. R4. Each Reliability Coordinator shall perform ensure that a Real-time Assessment is performed at least once every 30 minutes. R13. Each Transmission Operator shall ensure perform that a Real-time Assessment is performed at least once every 30 minutes. 12

118 Technical Summary IRO/TOP IRO R3 and TOP R10 Requirements re-structured for clarity Sub-100 kv data clarified identified as necessary added to relieve concerns over reaching for unnecessary data Clarified Reliability Coordinator role for System Operating Limits (SOLs) Special Protection System term retained if the project on re-defining terms receives approval, all applicable standards will be revised at that time R4 (R3). Each Reliability Coordinator shall monitor Facilities, the status of Special Protection Systems, and sub-100 kv facilities identified as necessary by the Reliability Coordinator, within its Reliability Coordinator Area and neighboring Reliability Coordinator Areas to identify any System Operating Limit exceedances and to determine any Interconnection Reliability Operating Limit exceedances within its Reliability Coordinator Area. 13

119 Technical Summary - IRO IRO NEW Purpose To ensure that outages are properly coordinated in the Operations Planning time horizon and Near-term Transmission Planning Horizon Responsive to NOPR issues, IERP and SW Outage Report recommendations Intent of Operations Planning time horizon: The official definition of the Operations Planning Time Horizon is: operating and resource plans from day ahead up to and including seasonal. The SDT equates seasonal as being up to one year out and that these requirements covers the period from day-ahead to one year out Requirement R4 re-structured to show that the process starts with the Planning Assessments created by the Planning Coordinator and Transmission Planner and then those Planning Assessments are reviewed and reconciled as needed with the Reliability Coordinator 14

120 Technical Summary - Whitepaper Clarification of SOL exceedance (white paper) The Whitepaper is designed to provide the industry with a concise document that highlights existing NERC Standard Requirements and NERC Defined Terms, including examples, in an effort to promote clarity, consistency, and a common understanding of the concepts associated with establishing SOLs, exceeding SOLs, and implementing Operating Plans to prevent and mitigate SOL exceedance. SOL Defined Term includes pre- and post-contingency Facility Ratings, Transient Stability Ratings, Voltage Stability Ratings, and System Voltage Limits. Specific references to Requirements within approved FAC (Facility Ratings), approved FAC (System Operating Limits Methodology for the Operations Horizon), approved FAC (Establish and Communicate System Operating Limits), proposed TOP (Transmission Operations), and proposed TOP (Operations Planning). Takes into account the time-based nature of Facility Ratings Provides references to appropriate FAC and TOP standard requirements 15

121 Technical Summary Compliance Data Retention IRO and TOP-002-4: changed data retention for analyses from six months to 90 calendar days to alleviate burden IRO and TOP-002-4: changed data retention for voice recordings from three months to 90 calendar days for consistency IRO and TOP-001-3: changed data retention from current calendar year and one previous calendar year to a rolling 30 day period for Real-time Assessments to alleviate burden IRO-014-3: added missing item for Requirements R7 (now R5) and R9 (now R7) TOP-001-3: changed operator logs to 90 calendar days RSAWs For certain Requirements, the auditor is advised to select a sample of BES Events that are identified as part of EOP-004 reportable. 16

122 VRFs IRO-010-2, Requirements R1 and R2: changed from Medium to Low for consistency with approved IRO-010-1a, Requirement R1 and proposed TOP-003-3, Requirement R1 IRO-017-1, Requirements R1, R2, and R3: changed from Low to Medium to be consistent with approved IRO a, Requirement R6 IRO-002-4, Requirement R2 (now R1) changed from binary (severe) to incremental approach 17

123 Technical Summary Compliance VSLs IRO-008-2, Requirement R5 (now R4) - changed from binary (severe) to incremental approach IRO-017-1, Requirement R1 - changed from binary (severe) to incremental approach TOP-001-3, Requirement R8: added an incremental approach to account for differential impacts on smaller entities TOP-003-3, Requirement R5: added incremental approach for consistency with approved IRO-010-1a, Requirement R1 The SDT did not change the VSLs associated with Operating Instructions. These VSLs are proposed to be binary (severe). The requirement language is written on a single Operating Instruction basis. Therefore, the entity either does the action or it doesn t. 18

124 19

125 Next Steps - Ballot Results Standard 1 st Ballot 2 nd Ballot* Final Ballot IRO % 76.05% October IRO % 74.05% October IRO % 75.54% October IRO % 84.21% October IRO % 75.60% October IRO % 78.40% October TOP % 48.04% November TOP % 78.77% October TOP % 85.72% October Definitions 62.64% 93.04% October 20 * Draft Ballot Results * Dr

126 21

127 ERO Enterprise Compliance Auditor Manual & Handbook NERC Standards and Compliance Fall Workshop September 23-25, Presentation Team Andrew Williamson, FRCC Adina Mineo, NERC

128 Agenda Project Overview Manual and Handbook Format, Style, and Design Handbook Overview Questions and Answer Session 2

129 Project Overview Project Milestones and Accomplishments Next Steps and Key Deliverables Training Approach and Schedule Manual and Handbook Format, Style, and Design 3

130 Milestones and Accomplishments June July Aug Sep Oct Nov Dec Jan 2013 June Drafting team formed September Handbook format and preliminary content presented to compliance auditors December Handbook contents delivered to regional executives 2014 January Drafting team reviews feedback and updates the handbook for final first draft edits 4

131 Milestones Feb March April May June July Aug Sep Oct Nov Dec March 3 rd Approved handbook provided to Compliance Auditors April 1 st Published handbook on the NERC website August 8 th Complete training for all Compliance Auditors September 1 st All audit engagement use and follow the handbook Industry Perspective Common language to communicate with industry Standardized audit approach across the ERO Enterprise Transparent audit activities 5

132 Handbook Training for Auditors All auditors review Handbook and attend appropriate training Q Q Q Q Q Spring Workshop Webinar 1 Continued rollout in each region Webinar 2 Webinar 3 Webinar 4 Webinar 5 Webinar 6 Fall Workshop Incorporated into online courses and Team Leader training Spring Workshop * February Initial rollout in each region * September 1 st Fully implemented

133 Checklist to Handbook Compliance Audit Check List Area Task Action The Handbook is designed to support the Checklist layout. The Handbook will consist of 5 Areas; 30 Tasks; and 77 Action Items. XX-XXXX Area Each section of the checklist is supported by a page that further explains the Area; Task; and Action Item. Task Action Items 7

134 Handbook What is the Auditor Handbook? In addition, what the Auditor Handbook is not Where did the Auditor Handbook come from? Who developed it 8

135 Handbook Where did the Auditor Handbook come from? ERO Audit Checklist Regional Entity Executives ERO wide team assembled to develop it. 9

136 Handbook Drafting Team Executive Sponsor Ron Ciesiel General Manager Southwest Power Pool Regional Entity Development Team Lead Drafter Jerry A. Hedrick, Jr., MBA, CFE Associate Director of Compliance Operations North American Electric Reliability Corporation Drafting Team Bill Beaver, MBA, CISA CIP Audit Manager Texas Reliability Entity Ken Gartner, CPA, CISSP, CISA, CRISC CMEP Process Principal, Midwest Reliability Organization Kevin Goolsby, PE Senior Auditor, SERC Reliability Corporation Ben Eng Manager, Compliance Audits and Investigations O&P Northeast Power Coordinating Council, Inc. Kevin B. Perry, CISA, CRISC Director, Critical Infrastructure Protection, Southwest Power Pool Regional Entity Andrew Williamson, MBA, PMP Senior Compliance Engineer Florida Reliability Coordinating Council Mike Hughes, PE Lead Compliance Engineer Southwest Power Pool Regional Entity Gary Campbell Manager of Operations and Planning Audits, ReliabilityFirst Expert Reviewers Dennis Glass Compliance Analyst II Texas Reliability Entity Kristi Knight, MBA, CIA, CRMA Auditor Training Specialist, NERC Adina Mineo, MBA, CPA Sr. Compliance Auditor NERC Frank Vick - Compliance Team Lead, Texas Reliability Entity Editorial Team Miggie E. Cramblit VP General Counsel Corporate Secretary and Director of External Affairs Midwest Reliability Organization Technical Support Team Brooke Thornton Administrative Assistant, NERC Monica Polo Executive Assistant, NERC Pat Moast Compliance Auditor Western Electric Coordinating Council

137 What the Handbook is: Companion Document to the ERO Auditor Checklist Process guide One Section or Chapter of the Auditor Manual A tool for both the experienced and new auditor An auditor tool to support good audit practices 11

138 What the Handbook is: A section of the Auditor Manual that: Intends to be practical & used as a reference document Serving both new and tenured auditors, and compliance personnel & management Informs Who is responsible for doing its action items What is the audit work & audit work papers When an activity is to be done Implements consistency of approach & risk assessment 12

139 What the Handbook is NOT: A tool that will tell an auditor how to determine compliance Does not interpret a Reliability Standard Does not limit auditor professional judgment 13

140 Compliance Auditor Tool Kit Manual Compliance Activities: 1. When 2. How 3. What & Handbook Reinforce: 1. Activities 2. Methodology 3. Approach RSAWs Training Tools & Processes Compliance Design: 1. Templates 2. Requirements Standard Specific Test Plans & Methodology Auditor Knowledge and Experience 14 14

141 Handbook Handbook Overview and Organization Area 01- Pre-Audit 02- Planning 03- Fieldwork 04- Reporting 05- Performance Task Action Item 15

142 Manual Location Located under Compliance Tools and Auditor Resources Compliance-Auditor-Manual.aspx 16

143 Handbook Number Formatting XX - XXXX Area XX - Task XX Action Item XX The first two digits indicate the Area: 01- Pre-Audit 02- Planning 03- Fieldwork 04- Reporting 05- Performance Checklist Alignment: The number formatting currently matches the Checklist to reflect the five Audit Cycle Areas. The middle two digits indicate the Task. Each Area is typically made up of multiple tasks. There are a total 30 tasks across 5 areas in the check list. This provides for expansion of Tasks within each area. Checklist Alignment: The use of a decimal place is replaced with a two digit designate following the dash. The numbering sequence provides for expansion without impacting the number formatting. The last two digits indicate the Action Items. There are a total of 79 Actions within the 30 Tasks, across the five Areas. Again, the numbering sequence allows for expansion if necessary. Checklist Alignment: Bullet points in the Checklist are replaced with a two digit trailer in order to provide a smooth reference to specific Action Items within the Task. Examples are provided on the next page to demonstrate the number formatting 17

144 Audit Cycle and Checklist Areas Checklist Area Cycle Color Pre-Audit Planning Audit Cycle Fieldwork Reporting Performance Assessment 18

145 19 Area Pre-Audit Audit Planning Task Number Task Pre-Audit Planning regeistered entitiy Evaluation Audit Scoping Detail Planning ERO Enterprise Compliance Auditor Audit Cycle Checklist Action Item Number Action Items Perform independence and conflict of interest checks for each auditor (both employees and consultants) Reconfirm each auditor is in compliance with internal requirements (i.e., NERC training, HR forms, etc.) Reconfirm the auditors are aware of up-to-date audit methodology and templates. Research the history and functions of registered entity along with all registrations and system topology, facilities, adjoining/neighboring systems, etc. Additional information needed should be captured for the initial request list. Information from previous monitoring activities should be appropriately captured and reviewed. Understand agreements between the registered entity and other parties (e.g. Reliability Coordinators, RTO/ISOs, Planning Authorities, Transmission Operators, Generator Operators, Balancing Authorities, and other non registered entities) Understand the registered entity s management and organizational structure (including subsidiaries). Meet with Enforcement (or Risk Assessment/Mitigation/Analytics) to discuss risks and any events pending enforcement actions, mitigation, or self-reporting Confirm with NERC and FERC that there is no pending activity related to the Registered Entity. Seek public/industry information on: Categories Level 1, 2, 3, and 4 events. Emergency Operations Planning (EOP) reporting, Events Analysis, and Investigation Reporting Reliability statistics including internal registered entity statistics on system performance, EMS/SCADA outages, etc. Review subsidiary information, including coordinating with other Regional Entities with registered entity operations in other jurisdictions. Use historical information and background on facilities owned/operated by the registered entity to develop an expected model of the key inherent audit risks and determine potential in-scope reliability standards. Determine initial scope based on NERC AML for the audit year. Consider other Reliability Standards not in the AML which were identified in the Reliability Assessment Identify recent industry trends and risks for the areas in scope to be considered during the audit Identify the Reliability Standards and Requirements, areas of focus, and time period that will be in Document audit scope, audit objectives, risks, and preliminary test procedures (i.e., RSAW). Identify engagement risks (i.e., loss of key resources, participant delays, physical access constraints, data loss, etc.).

146 Handbook Task Flow Production

147 Handbook Task Flow Evaluating the registered entity is the first of Ten Tasks in Entity Evaluation area: ( ) Registered Entity History and Functions ( ) Contractual Obligations ( ) Organizational and Corporate Structure ( ) Regional Entity Enforcement Considerations ( ) NERC Audit Considerations ( ) Registered Entity Research ( ) Registered Entity Subsidiaries & Regional Presence ( ) Entity Profile and Reliability Assessment 21

148 Handbook Action Item Process Flow

149 23

150 Manual What the Auditor Manual is: A larger document that has the Auditor Handbook and Auditor Checklist as the two first components Examples of possible future content Sampling Methodology Internal Controls Evaluation (ICE) Inherent Risk Assessment (IRA) How the ERO Auditor Manual will be maintain: Sub-team of ERO Auditor Handbook Drafting Team ECEMG Oversight 24

151 25 RAI Impact on Auditor Manual

152 Compliance Oversight Objectives Consistent application Identify training needs Develop additional guidance 26

153 Manual Task Force Members Name Region Kevin Goolsby, Chairman SERC Andrew Williamson FRCC Bill Beaver Texas RE Mike Hughes SPP RE Adina Mineo NERC 27

154 Questions? Future Questions on the ERO Manual 28

155 Standards Standards Becoming Enforceable in 2015 Laura Hussey, Director of Standards Development Mark Olson, Standards Developer Darrel Richardson, Standards Developer Standards and Compliance Workshop September 23, 2014

156 Newly Enforceable Standards (2015) January 1, 2014 TPL Transmission System Planning Performance Requirements (R1 and R7) April 1, 2015 BAL Frequency Response and Frequency Bias Setting (R2, R3, R4) EOP Geomagnetic Disturbance Operations (R1 and R3) PRC Protection System Maintenance July 1, 2014 MOD Data for Power System Modeling and Analysis (R1) Two Regional Standards PRC-006-NPCC-1 (July 1, 2014) PRC-006-SERC-01 (October 1, 2014) 2

157 How to Find This Information 3

158 TPL Transmission System Planning Performance Requirements Laura Hussey, Director of Standards Development Standards and Compliance Workshop September 23, 2014

159 Two Requirements Become Enforceable in 2015 Each Transmission Planner and Planning Coordinator shall maintain System models for performing the studies needed to complete its Planning Assessment (R1) Each Planning Coordinator, in conjunction with each of its Transmission Planners, shall determine and identify each entity s individual and joint responsibilities for performing the required studies for the Planning Assessment. (R7) 5

160 Complete Implementation 2016 through 2021 January 1, 2016: Requirements R2 through R6 and R8 become enforceable Until December 31, 2020: Corrective Action Plans applying to certain categories of Contingencies and events are allowed to include Non-Consequential Load Loss and curtailment of Firm Transmission Service that would not otherwise be permitted by TPL See standard and implementation plan for details 6

161 How to Find the Implementation Plan Click Here 7

162 8

163 EOP Geomagnetic Disturbances Mark Olson, Standards Developer Standards and Compliance Workshop September 23, 2014

164 EOP GMD Operations Requires Reliability Coordinators (RC) to develop Operating Plans to coordinate GMD Operating Procedures in their area Requires Transmission Operators (TOP) to develop GMD Operating Procedures that include: Steps to receive space weather information System Operator actions based on predetermined conditions Applies to RCs and TOPs with grounded transformers >200 kv U.S. enforcement date April 1, 2015 Exception: RC requirement in EOP-010 to disseminate space weather information is contingent upon retirement of IRO a 10

165 Resources NERC GMD Task Force project page contains resources for entities to use in developing Operating Procedures Operating Procedure template approved by Planning and Operating Committees Examples of Operating Procedures currently in use Templates provide flexibility for entities to tailor procedures Force-(GMDTF)-2013.aspx 11

166 Geomagnetic Disturbances Solar Flare CME Space Interaction with Earth s Magnetic Field B t Maxwell Eq. & Earth Cond. Model E Near Earth s Surface System Model GIC Geomagneticallyinduced currents (GIC) can cause: Increased reactive power consumption Transformer heating Protection System misoperation 12

167 Operating Procedures GMD Operating Procedures contain operator actions designed to mitigate impacts of GMD events in response to warnings: Increase situational awareness Posture the system Reconfigure the system System studies and monitoring enhance the effectiveness Recommended operating procedures and industry bestpractices were developed by the NERC GMD Task Force 13

168 Long Lead-Time (1-3 days) Operators increase situational awareness and prepare for contingencies System may be postured for resilience Return equipment to service Delay maintenance 14

169 Day-of-event (from Hours to Imminent) Operators increase situational awareness Monitor space weather Monitor system conditions NOAA Space Weather Prediction Center 15

170 Day-of-event (from Hours to Imminent) Operators increase situational awareness System posturing Reconfiguration, increase generation, or limit transfers 16

171 Real-Time Actions System operators adhere to established limits for voltage stability and equipment ratings Manual operation of transformer cooling fans may increase thermal margin Monitor space weather information for storm progression 17

172 Return to Normal Operations Typically two to four hours after geomagnetic activity ends 18

173 Additional Resources GMD Task Force is developing an information guide for operators: Space weather phenomenon Historical GMD events Impacts on the power system equipment Prediction and warning capabilities Operator actions Reference: 2012 GMD Report 19

174 20

175 BAL Frequency Response and Frequency Bias Setting Darrel Richardson, Standards Developer Standards and Compliance Workshop September 23, 2014

176 BAL Key Implementation Dates January 16, 2014 BAL approved by FERC January 23, 2014 Final rule published in Federal Register March 24, 2014 Effective Date (60 days after publication) April 1, 2015 R2, R3, and R4 Effective Date (Bias) April 1, 2016 R1 Effective Date (FRO) 22

177 BAL Compliance Dates April 1, 2015 R2, R3, and R4 Effective date (Bias) March 7, BAs submit FRS forms April 1, Compliance effective date December 1, 2014 through November 30, 2015 Event collection period April 1, 2016 R1 Effective Date (FRO) March 7, 2018 BAs submit FRS forms April 1, 2018 Compliance effective date December 1, 2016 through November 30, 2017 Event collection period 23

178 High Level BAL Schedule 24

179 BAL Implementation Schedule BAL approval date - March 24, 2014 Requirement R2, R3 & R4 effective - April 1, 2015 Requirement R1 effective April 1, 2016 Data collection for 2017 FRM Data collection for 2018 FRM J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N D Data collection for 2016 Bias Setting Data collection for 2017 Bias Setting Data collection for 2018 Bias Setting Data collection for 2019 Bias Setting 2016 Bias Setting in Place 2017 BA FROs in Place 2017 Bias Setting in Place 2018 BA FROs in Place File 2017 FRM Report 2018 Bias Setting in Place Frequency Characteristic Data for 2017 IFRO calculation Frequency Characteristic Data for 2018 IFRO calculation Frequency Characteristic Data for 2019 IFRO calculation Frequency Characteristic Data for 2020 IFRO calculation NEL Data for 2017 BA FRO Calculation NEL Data for 2018 BA FRO Calculation NEL Data for 2019 BA FRO Calculation NEL Data for 2020 BA FRO Calculation J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N D IFR Performance Data for 2017 IFRO calculation IFR Performance Data for 2018 IFRO calculation IFR Performance Data for 2019 IFRO calculation IFR Performance Data for 2020 IFRO calculation Calc IFROs Final 2017 IFROs 2017 BA FROs in Place Calc IFROs Final 2018 IFROs 2018 BA FROs in Place Calc IFROs Final 2019 IFROs 2019 BA FROs in Place 25

180 Balancing Authority Submittal Website Currently being tested Targeted in-service date October 15, 2014 Private Secured SharePoint Site for BAL data submittals Common area for: Current FRS Forms and instructions Frequency Events lists and related data Other related information Exclusive BA-level submittal areas Able to read and download forms from common area Read, Write, delete for their BA only Cannot look at data from other BAs User s guide and future training webinar 26

181 27

182 NERC Auditor Scenario-Based Training PRC Protection System Maintenance 1

183 PRC Training Objectives Enhance auditor technical knowledge of Standard Provide examples of compliant practices Provide examples of deficient practices Provide examples of gray area practices Discussion of compliance assessment approach 2

184 Definition of Protection System Component Type Protective relays which respond to electrical quantities, Communications systems necessary for correct operation of protective functions, Voltage and current sensing devices providing inputs to protective relays, Station dc supply associated with protective functions (including batteries, battery chargers, and non-batterybased dc supply), and Control circuitry associated with protective functions through the trip coil(s) of the circuit breakers or other interrupting devices. The above is from the definition for Protection System in the NERC Glossary of Terms 3

185 Definition of Protection System Component A component is any individual discrete piece of equipment included in a Protection System, including but not limited to a protective relay or current sensing device. Example: monitored microprocessor relay 4

186 R1.1 Verify maintenance method for each Component Type Three methods: Time-based Performance-based Combination of both 5

187 Process Overview The following slides are indicative of typical evidence received from Utopia Electric Company as envisioned by GDS based on its experience in developing PSMPs They are not intended to represent the entire program These slides are examples of possible evidence These slides are not intended to indicate all possible documentation that can be utilized to show compliance A visual indicator of sufficiency has been developed to aid in determining compliance status Green arrows and text indicate a positive compliance outlook Black arrows and yellow text boxes indicate areas that may require additional information ( Grey area practices ) Red arrows and text indicate a poor compliance posture with possible non-compliant implications 6

188 This box is the heading for the Compliance Assessment Approach Specific to PRC , requirement n (R1) this box contains salient points of the RSAWs Audit Approach Section regarding compliance to the requirement. NOTE: the wording in the Audit Approach may not be identical to the wording of the Requirement. The Audit Approach is meant to guide the auditor. This is a set-up slide. Language from the draft RSAW are shown in section above. Entity evidence shown in section to the right. 7

189 Compliance Assessment Approach Specific to PRC , R1 (R1) Verify that each Transmission Owner, Generator Owner and Distribution Provider has a documented PSMP in accordance with Requirement R1. Entity shows universe of individual Components included in a Protection System Maintenance Program PSMP 8

190 Compliance Assessment Approach Specific to PRC , R1.1 (R1.1) Verify that the entity PSMP identifies which maintenance method (s) (time-based, performance-based per PRC-005 Attachment A, or a combination) is used to address each Protection System Component Type. NERC Standard PRC Rev. Number: 0 Procedure Number: OP-PRC-005 Rev. Date: Page Number: 15 of 40 Entity selects timebased method (TBM) Except protective relays which are combination of performance-based method (PBM) and TBM Maintenance Method Based upon the scope of equipment, simplicity in implementation, and productivity, Utopia Electric Company has chosen to utilize the TBM electrical maintenance and testing strategy for all Component Types (except for protective relays) with the maintenance and testing interval specified in PRC Tables 1-1 through 1-5, 2 and 3. Protective relays utilize a combination of TBM and PBM to establish testing intervals. 9

191 Compliance Assessment Approach Specific to PRC , R1.1 (R1.1) Verify that the entity PSMP identifies which maintenance method (s) (time-based, performance-based per PRC-005 Attachment A, or a combination) is used to address each Protection System Component Type. Entity has not stated that it selected TBM or combination of TBM and PBM for relays. Discussion? 10

192 R1.2 Include the applicable monitored Component attributes applied to each Component Type where monitoring is used to extend the maintenance intervals Monitored attributes used to extend maintenance intervals may include: Measurement, comparison, self-diagnosis, alarms Periodic automated testing 11

193 Compliance Assessment Approach Specific to PRC , R1.2 (R1.2) Verify that the entity PSMP identifies the applicable monitored Component attributes of the Components within the Component Type, used to extend the maintenance intervals beyond those specified for unmonitored Protection System Components. Attributes that shall be identified are provided in the Component Attributes column in Tables 1-1 through 1-5, Table 2, and Table 3, PRC Entity employs Table 1-1 and Table 2 to extend to Maximum Maintenance Interval. Entity employs PBM for a Segment of the relay population. 12

194 Compliance Assessment Approach Specific to PRC , R1.2 (R1.2) Verify that the entity PSMP identifies the applicable monitored Component attributes of the Components within the Component Type, used to extend the maintenance intervals beyond those specified for unmonitored Protection System Components. Attributes that shall be identified are provided in the Component Attributes column in Tables 1-1 through 1-5, Table 2, and Table 3, PRC There is no evidence demonstrating basis for 15 year interval. Discussion? 13

195 Compliance Assessment Approach Specific to PRC , R1.2 (R1.2) Verify that the entity PSMP identifies the applicable monitored Component attributes of the Components within the Component Type, used to extend the maintenance intervals beyond those specified for unmonitored Protection System Components. Attributes that shall be identified are provided in the Component Attributes column in Tables 1-1 through 1-5, Table 2, and Table 3, PRC Entity utilizes the component attribute of Alarm Path with monitoring to extend maintenance interval by receiving and acting upon the alarm within 24 hours per Table 2. NERC Standard PRC SCADA Alarms Rev. Number: 0 Procedure Number: OP-PRC-005 Rev. Date: Page Number: 18 of 40 Utopia Electric Company monitors all Components of its microprocessor protective relay population using its SCADA system. The Utopia System Operator monitors, via SCADA, the state of the self-test alarm contact and other critical protection system components. Communications circuits to the substation RTU are monitored and alarmed for loss of signal. When an alarm is received, the System Operator immediately dispatches the on-call test technician to the substation. 14

196 Compliance Assessment Approach Specific to PRC , R1.2 (R1.2) Verify that the entity PSMP identifies the applicable monitored Component attributes of the Components within the Component Type, used to extend the maintenance intervals beyond those specified for unmonitored Protection System Components. Attributes that shall be identified are provided in the Component Attributes column in Tables 1-1 through 1-5, Table 2, and Table 3, PRC Entity captures the alarm but the alarm is not reported within 24 hours to initiate corrective action. If using TBM, Utopia must set maximum maintenance interval for microprocessor relay Components to 6 years. NERC Standard PRC SCADA Alarms Rev. Number: 0 Procedure Number: OP-PRC-005 Rev. Date: Page Number: 18 of 40 Utopia Electric Company monitors its microprocessor protective relays using its SCADA system. The Utopia Substation Test Supervisor reviews all SCADA alarm logs on a weekly basis. If any relay self-test alarms are found, the Test Supervisor will initiate a work order for a test technician to repair. 15

197 R2 Performance-Based Maintenance intervals follow Attachment A Entity must: Have complete list of designated Segments (minimum 60 Components) Maintain Components according to the maximum timebased intervals (Tables) until results for minimum of 30 Components are available In subsequent years, maintain at least 3 Components or 5% of population whichever is greater Have analysis of program activities and results for all segments annually Establish interval such that Segment (greater of last 30 Components maintained or all Components maintained the previous year) produces </= 4% Components that have Countable Events on annual basis 16

198 Definition of Segment Protection Systems or components of a consistent design standard, or a particular model or type from a single manufacturer that typically share other common elements. Consistent performance is expected across the entire population of a Segment. A Segment must contain at least sixty (60) individual components. Example: SEL-351A Protective Relay 17

199 Compliance Assessment Approach Specific to PRC , R2 Select all, or a sample, of the designated performance-based Segments of the Protection System. For each Segment selected, verify that the initial Segment was comprised of at least 60 Components. Verify all technical justifications prepared since the last audit to establish a PBM Program following the procedures established in PRC-005-2, Attachment A. Entity identifies each Segment of its Protection System by manufacturer and model # Location ANSI Standard Device Number Utopia Primary #1 21/50/51 Utopia Primary #1 21/50/51/27 Area of Protection Segment Interval Green CT Switching Station SEL-311C 12 Years Green CT Switching Station SEL Years Utopia Primary #1 50/51/62/79 Byron 115kV SEL 351A 12 Years Utopia Primary #1 21/50/51/27 Byron 115kV SEL Years Hempstead 230 kv 50/51/62/79 Bank C SEL 351A 12 Years Hempstead 230 kv 21 Door County 230kV KD-10 8 Years Hempstead 230 kv 21 Franklin 230kV KD-10 8 Years Hempstead 230 kv 21 Door County 230kV KD-11 6 Years Hempstead 230 kv 21 Franklin 230kV KD-11 6 Years 18

200 Compliance Assessment Approach Specific to PRC , R2 Validate that the entity maintained the Components in each initial Segment according to the timebased maximum allowable intervals established in Tables 1-1 through 1-5, and Table 3, PRC as part of the process to establish the Segment. Entity maintained initial Segments of SEL- 311, 321 and KD-11 at TBM Table 1-1 and Table 2 intervals. SEL-351 at a TBM interval of 15 years. KD-10 at PBM interval of 6 years. Location ANSI Standard Device Number Utopia Primary #1 21/50/51 Utopia Primary #1 21/50/51/27 Area of Protection Segment Interval Green CT Switching Station SEL-311C 12 Years Green CT Switching Station SEL Years Utopia Primary #1 50/51/62/79 Byron 115kV SEL 351A 15 Years Utopia Primary #1 21/50/51/27 Byron 115kV SEL Years Hempstead 230 kv 50/51/62/79 Bank C SEL 351A 15 Years Hempstead 230 kv 21 Door County 230kV KD-10 6 Years Hempstead 230 kv 21 Franklin 230kV KD-10 6 Years Hempstead 230 kv 21 Door County 230kV KD-11 6 Years Hempstead 230 kv 21 Franklin 230kV KD-11 6 Years 19

201 Definition of Countable Event A failure of a component requiring repair or replacement, any condition discovered during the maintenance activities in Tables 1-1 through 1-5 and Table 3 which requires corrective action, or a Misoperation attributed to hardware failure or calibration failure. Misoperations due to product design errors, software errors, relay settings different from specified settings, Protection System component configuration errors, or Protection System application errors are not included in Countable Events. 20

202 Compliance Assessment Approach Specific to PRC , R2 Validate that the entity analyzed the maintenance program activities and results for each Segment to determine the overall performance of the Segment. Entity recorded KD-10 Segment countable event associated with relay voltage restraint Analysis of Protection System Performance Report January 2013 Westinghouse KD-10 (21P, 21S) Total in Segment: 124 Failures & Corrective Actions Capacitor failures detected by loss of voltage constraint. April units at Hempstead 230 kv tested with contact closure at 95% of pick-up setting. Capacitors replaced from spares and relay placed in-service. 21

203 Compliance Assessment Approach Specific to PRC , R2 Validate that the entity documented the maintenance program activities and results for each selected initial Segment, included maintenance dates and Countable Events. Location Utopia Primary #1 Utopia Primary #1 Area of Countable Segment Prior Test Date Protection Events Green CT Switching Station SEL-311C 12/19/ Green CT Switching Station SEL /19/ Utopia Primary #1 Byron 115kV SEL 351A 12/19/ Utopia Primary #1 Byron 115kV SEL /19/ Entity tracked maintenance dates and Countable Events by Segment type Hempstead 230 kv Bank C SEL 351A 4/1/ Hempstead 230 kv Door County 230kV KD-10 4/1/ Hempstead 230 kv Franklin 230kV KD-10 4/1/ Hempstead 230 kv Door County 230kV KD-11 4/1/ Hempstead 230 kv Franklin 230kV KD-11 4/1/

204 Compliance Assessment Approach Specific to PRC , R2 Validate that the entity performed maintenance on at least the greater of 5% of the components (addressed in the performance-based PSMP) in each Segment or 3 individual Components within the Segment each year Entity performed calibration on >5% components in KD-10 segment 23

205 Compliance Assessment Approach Specific to PRC , R2 Validate that, if the Components in a Protection System Segment experienced a Countable Event rate exceeding 4% of the Components within the Segment, for the greater of either the last 30 Components maintained or all Components maintained in the previous year, the entity developed, documented, and implemented a corrective action plan to reduce the Countable Event rate to 4%. Entity experienced a Countable Event Rate >4%. A Corrective Action Plan (CAP) is required. 24

206 Compliance Assessment Approach Specific to PRC , R2 Validate that, if the Components in a Protection System Segment experienced a Countable Event rate exceeding 4% of the Components within the Segment, for the greater of either the last 30 Components maintained or all Components maintained in the previous year, the entity developed, documented, and implemented a corrective action plan to reduce the Countable Event rate to 4%. Entity implemented a Corrective Action Plan to reduce Countable Event Rate Relay Department Corrective Action Plan Date: 4/1/2012 I. BRIEF DESCRIPTION OF ISSUE/PROBLEM During calibration, Aφ element picked up at 114V (95%), 1.0A, MTA = 45º II. ROOT CAUSE EVALUATION (Include 5 WHY s or other method) Tested 12.5 μf capacitor and found it shorted. III. CORRECTIVE ACTION STEPS AND TIMEFRAMES Corrective Action #1 - Identify all KD-10 relays with 12.5 μf capacitors Planned Completion Date 05/15/2013 Corrective Action #2 - Replace 12.5 μf capacitors in all KD- 10 relays Planned Completion Date 07/15/2013 IV. IMPROVEMENT BENCHMARK(S) (Will Corrective Action prevent future similar problems) Replacement of all 12.5 μf capacitors will prevent recurrence of loss of voltage restraint and potential subsequent mis-operations Approved By: John J. Pasierb 25

207 R3 verify Entity maintained its Protection System Components that are included within the TBM program in accordance with the minimum maintenance activities and maximum maintenance intervals prescribed within Tables 1-1 through 1-5, Table 2, and Table 3. Maximum Maintenance Interval determined by component attributes in Tables Monitored attributes are used to extend the maintenance intervals beyond those specified for unmonitored Protection System Components. 26

208 Compliance Assessment Approach Specific to PRC , R3 Verify that all, or a sample of, the Protection System Components (and Alarm Paths) included within the timebased maintenance program were maintained in accordance with the minimum maintenance activities and maximum maintenance interval s prescribed in Tables 1-1 through 1-5, Table 2, and Table 3. Consider validating a sample of reporting dates by examining actual field data. Table 1-5. Entity: (1) at 6 year maximum interval verifies electrical operation of electromechanical lockout devices NERC Standard PRC D.C. Control Circuit Testing Every 6 calendar years: Rev. Number: 0 Procedure Number: OP-PRC-005 Rev. Date: Page Number: 30 of With the circuit breaker open and isolated and the lockout relay reset, manually close the output contacts of the electromechanical relay. The lockout relay should trip. Reset the lockout and repeat for each tripping relay. This effectively tests the control circuit(s) in the relay panel. 2. With the circuit breaker closed and isolated and the lockout relay reset, manually close the output contact of a relay. The lockout relay and circuit breaker should trip. This effectively tests the control circuit through the breaker trip coil. 3. Record the results of the test. (2) verifies that each trip coil is able to operate the circuit breaker, interrupting device, or mitigating device. 27

209 Compliance Assessment Approach Specific to PRC , R3 Verify that all, or a sample of, the Protection System Components (and Alarm Paths) included within the timebased maintenance program were maintained in accordance with the minimum maintenance activities and maximum maintenance interval s prescribed in Tables 1-1 through 1-5, Table 2, and Table 3. Consider validating a sample of reporting dates by examining actual field data. Entity supplies evidence of component type Control Circuitry, component attribute verification of trip coil (52), lockout relays (86) and auxiliary tripping relays (94). Signed and dated. Utopia Electric Generator #1 D.C. Elementary Diagram 28

210 Compliance Assessment Approach Specific to PRC , R3 Verify that all, or a sample of, the Protection System Components (and Alarm Paths) included within the timebased maintenance program were maintained in accordance with the minimum maintenance activities and maximum maintenance interval s prescribed in Tables 1-1 through 1-5, Table 2, and Table 3. Consider validating a sample of reporting dates by examining actual field data. Entity does not supply evidence of component type Control Circuitry, component attribute verification of lockout relays (86) and auxiliary tripping relays (94). 29

211 Compliance Assessment Approach Specific to PRC , R3 Verify that all, or a sample of, the Protection System Components (and Alarm Paths) included within the timebased maintenance program were maintained in accordance with the minimum maintenance activities and maximum maintenance interval s prescribed in Tables 1-1 through 1-5, Table 2, and Table 3. Consider validating a sample of reporting dates by examining actual field data. Electrolyte levels were verified as evidenced by check box indication. Electromechanical protective relay was tested to determine if calibration was required (calibration to occur if outside the expected value including the ± variance allotted). Evaluation column indicates whether or not protective relay passed. Inspection was performed for unintentional grounds 30

212 Compliance Assessment Approach Specific to PRC , R3 Verify that all, or a sample of, the Protection System Components (and Alarm Paths) included within the timebased maintenance program were maintained in accordance with the minimum maintenance activities and maximum maintenance interval s prescribed in Tables 1-1 through 1-5, Table 2, and Table 3. Consider validating a sample of reporting dates by examining actual field data. Utopia Power Company provides the previous and last test dates to show the interval was met. Discussion? 31

213 R4 -implement and follow its PSMP for its Protection System Components that are included within the performance-based program List of all PBM Segments established and maintained by the registered entity List of all components comprising the PBM Segment established and maintained by the registered entity, a list of all components comprising the Segment, effective on the date of the annual Segment component update PBM interval in effect for each year by PBM Segment. Evidence that specific activities performed satisfied the minimum maintenance activities requirements of Table 1-1 through 1-5, Table 2, and Table 3. 32

214 Compliance Assessment Approach Specific to PRC-005-2, R4 Component or Path Identification Location Utopia Primary #1 Hempstead 230 kv Function Directional Overcurrent relay Directional Overcurrent relay ANSI Standard Device Number Area of Protection Segment Interval 50/51/67/67N Byron 115kV SEL 351A 15 Years 50/51/67/67N Bank C SEL 351A 15 Years 33

215 Compliance Assessment Approach Specific to PRC-005-2, R4 Component or Physical Location Location Utopia Primary #1 Hempstead 230 kv Function Directional Overcurrent relay Directional Overcurrent relay ANSI Standard Device Number Area of Protection Segment Interval 50/51/67/67N Byron 115kV SEL 351A 15 Years 50/51/67/67N Bank C SEL 351A 15 Years 34

216 Compliance Assessment Approach Specific to PRC-005-2, R4 Segment Location Utopia Primary #1 Hempstead 230 kv Function Directional Overcurrent relay Directional Overcurrent relay ANSI Standard Device Number Area of Protection Segment Interval 50/51/67/67N Byron 115kV SEL 351A 15 Years 50/51/67/67N Bank C SEL 351A 15 Years 35

217 Compliance Assessment Approach Specific to PRC-005-2, R4 Maintenance Interval Location Utopia Primary #1 Hempstead 230 kv ANSI Standard Function Device Number Directional Overcurrent relay50/51/67/ Area of Protection Segment Interval Test Date Test Date 67N Byron 115kV SEL 351A 15 Years Directional Overcurrent relay50/51/67/ 67N Bank C SEL 351A 15 Years

218 Compliance Assessment Approach Specific to PRC-005-2, R4 Last two performances of all maintenance activities Location Function ANSI Standard Device Number Area of Protection Segment Interval Test Date Test Date Utopia Primary #1 Hempstead 230 kv Directional Overcurrent relay Byron 115kV SEL 351A 15 Years /51/67/67N Directional Overcurrent relay 50/51/67/67N Bank C SEL 351A 15 Years

219 Compliance Assessment Approach Specific to PRC-005-2, R4 Component Attributes Location Function ANSI Standard Device Number Area of Protection Segment Interval Attributes Directional Utopia Overcurrent Primary #1 relay 50/51/67/67N Byron 115kV SEL 351A 15 Years Table 1-1: Continuous AC measurement Inputs and outputs monitored and alarmed Password protected Alarm Path with monitoring 38

220 Compliance Assessment Approach Specific to PRC , R4 1. Verify that all, or a sample, of the Protection System Components in PBM Segments were maintained in accordance with the PBM time intervals in effect in all years since the last audit. Entity maintained initial Segments of SEL- 311, 321 and KD-11 at TBM Table 1-1 and Table 2 intervals. SEL-351 at a PBM interval of 15 years. KD-10 at PBM interval of 8 years. Location ANSI Standard Device Number Utopia Primary #1 21/50/51 Utopia Primary #1 21/50/51/27 Area of Protection Segment Interval Green CT Switching Station SEL-311C 12 Years Green CT Switching Station SEL Years Utopia Primary #1 50/51/62/79 Byron 115kV SEL 351A 15 Years Utopia Primary #1 21/50/51/27 Byron 115kV SEL Years Hempstead 230 kv 50/51/62/79 Bank C SEL 351A 15 Years Hempstead 230 kv 21 Door County 230kV KD-10 8 Years Hempstead 230 kv 21 Franklin 230kV KD-10 8 Years Hempstead 230 kv 21 Door County 230kV KD-11 6 Years Hempstead 230 kv 21 Franklin 230kV KD-11 6 Years 39

221 Compliance Assessment Approach Specific to PRC , R4 2. Verify that the entity can provide supporting documentation that mandatory PBM maintenance activities reported as completed were in fact accomplished. Relay Test Report Tested By: JJP Date Tested: Station Relay Model No. Hempstead 230 kv Zone of Protection KD-10 Relay S/N D Door County 230 kv Zone 1 Compensator Settings MTA = 75º Tap = 1.45Ω S = 1 T = 5.8 Entity completed Table 1-1 maintenance activities for unmonitored relays: 1) Verify settings are as specified 2) Test and calibrate M = +.03 As-found Tests Aφ Bφ Cφ Pick-up/Drop Out 2.85A/2.79A 2.84A/2.83A 2.86A/2.83A MTA Pass/Fail P P p Notes: Replaced 12 MFD capacitor. Cleaned and burnished contacts. 40