Entergy Regional Reliability Coordinators (RC) as of 12/1/2012

Transcription

1 Entergy Regional Reliability Coordinators (RC) as of 12/1/2012 EDE OKGE SPA AECI MISO NLR LAGN CWAY LAGN PUPP CECD PLUM CECD BUBA CECD WMU LAGN OMLP CECD BBA CECD TVA # BA Reliability Coordinator 1 ERCO ERCOT ISO 1 MISO MISO RTO 2 EES 1 BBA 2 BUBA 3 BRAZ 4 CLEC 5 CSWS 6 CWAY 7 DERS CSWS DERS CECD EES SME 8 EDE 9 LAFA 10 LAGN 11 LEPA Southwest Power Pool RTO ERCO CLEC LAGN SOCO 12 NLR 13 OMLP BRAZ CECD LEPA LAFA 14 OKGE 15 PLUM 16 PUPP 17 SPA 18 WMU Last Update: 08/30/12 BA Agent Acronym CECD LAGN Agent Name Constellation Energy Control & Dispatch Louisiana Generating, LLC 1 SME 2 SOCO Southern Company 1 TVA Tennessee Valley Authority 2 AECI 1

2 MISO Reliability Coordination Candidates for 6/1/2013 # Acronym BA Name NLR LAGN CWAY LAGN PUPP CECD BUBA CECD DERS CECD WMU LAGN PLUM CECD OMLP CECD 1 CLEC CLECO 2 SME South Mississippi Electric Power Association 3 LAGN Louisiana Generating, LLC 4 LAFA Lafayette Utilities System 5 LEPA Louisiana Energy and Power Authority 6 BRAZ Brazos Electric Cooperative 7 DERS City of Ruston, LA 8 OMLP City of Osceola, AR 9 PUPP Union Power Partners, L.P. 10 PLUM Plum Point Energy Associates, LLC 11 WMU City of West Memphis, AR 12 BUBA City of Benton, AR CLEC SME 13 CWAY City of Conway, AR 14 NLR City of North Little Rock, AR BRAZ CECD LAFA LAGN LEPA Last Update: 11/30/12 BA Agent Acronym CECD LAGN Agent Name Constellation Energy Control & Dispatch Louisiana Generating, LLC

3 MISO Balancing Authorities (BA) Candidates for 12/19/2013 # Acronym BA Name NLR LAGN CWAY LAGN BUBA CECD WMU LAGN PLUM CECD OMLP CECD 1 EES Entergy (Louisiana, Texas, Mississippi, New Orleans, Arkansas*) * Entergy also committed to Arkansas Commission to split off Entergy Arkansas into a separate BA (EAI) 2 CLEC CLECO 3 SME South Mississippi Electric Power Association 4 LAGN Louisiana Generating, LLC 5 LAFA Lafayette Utilities System 6 LEPA Louisiana Energy and Power Authority PUPP CECD EES 7 BRAZ Brazos Electric Cooperative 8 DERS City of Ruston, LA DERS CECD 9 OMLP City of Osceola, AR 10 PUPP Union Power Partners, L.P. CLEC LAGN SME 11 PLUM Plum Point Energy Associates, LLC 12 WMU City of West Memphis, AR 13 BUBA City of Benton, AR 14 CWAY City of Conway, AR BRAZ CECD LAFA LEPA 15 NLR City of North Little Rock, AR Last Update: 11/30/12 BA Agent Acronym CECD LAGN Agent Name Constellation Energy Control & Dispatch Louisiana Generating, LLC

4 RC & BA Proposed Schedule Key Date(s) Milestone 12/31/12 Decision by BAs due to MISO: 1. Dissolve and become part of Entergy s BA * 2. Existing BA to join MISO* *Requires BAs to begin RC service with MISO Phase 1 Reliability Coordination 1/13 5/13 Reliability Plan 2/13 3/13 Operator Cycle Training TBD Site Visit 5/13 6/13 Parallel Ops 6/1/13 Reliability Coordination Start Phase 2 Market Integration 7/13 Open Loop Test Complete 9/13 Closed Loop Test Complete TBD Site Visit 9/13 10/13 Market Trials / Data Test 12/19/13 Market Integration Complete 4

5 Event Analysis Subcommittee Event Analysis Process Document Update Cycle Public comment Posted December 05, day comment period ends January 21, 2013 OC Approval/Consideration June, 2013 EMS Event Task Force Working with NERC EA to address the top reasons for EMS outages Trending Working Group Working with NERC RRM to review data Assigned to review previous cold weather events o NERC RRM has prepared a preliminary review for the workinggroup 1 RELIABILITY ACCOUNTABILITY

6 Event Analysis Subcommittee Lessons Learned Outreach to Forums EAS is working with NERC Training on developing training modules applicable to system operators. March 2013 OC Meeting Presentation Duke Energy Presentation 2 RELIABILITY ACCOUNTABILITY

7 Electric Transmission Performance Improvement Initiatives

8 Electric Transmission Performance Improvement Initiatives Disturbance Investigations Operations Review and Risk Analysis System Protection & Communications WG Reviews Electrical Equipment Review Safety Human Performance Tools 2012 Dominion 2 8/21/2012

9 Disturbance Investigation Process Disturbance Investigation System (DIS) implemented in 1996 and has evolved to include additional items since inception such as adding NERC TADS reporting. Over 2000 Investigations have been performed with the ever evolving process. Assigned nearly 7000 action items since the start of the program Dominion 3 8/21/2012

10 Overview of Dominion s Investigation Process Operation Occurs Event Closed 2012 Dominion 4 8/21/2012

11 Where does the process begin? Operations group analyzes every automatic (relay trip) operation of Transmission and Substation equipment. (excludes distribution circuit trips, unless requested) A thorough investigation of the relay and equipment operations is performed for any items that aren t operating as designed. Although it typically appears to be a correct operation, there are always opportunities for improvement Dominion 5 8/21/2012

12 Gathering the Data Sources Digital Fault Recorders Sequence of Events Recorders Digital Relays Traveling Wave Systems Fault Analysis and Lightning Location System (FALLS) 2012 Dominion 6 8/21/2012

13 Analyzing the Data Once all the data has been retrieved, the team must verify everything worked as intended. Sometimes unforeseeable events happen. Did the protection and primary equipment work the way we would expect them too? Is this a preferable operation? 2012 Dominion 7 8/21/2012

14 Outage Database General Information Fault Location(s) What Operated Operation Quality 2012 Dominion 8 8/21/2012

15 Disturbance Investigation Summaries Contain detailed analysis of the event. Assigned investigative action items to appropriate personnel. Assigned specific and/or generic corrective action items to appropriate personnel Dominion 9 8/21/2012

16 Disturbance Investigation Specific Correction Items Generic Correction Items Investigative Action Items 2012 Dominion 10 8/21/2012

17 Actions completed Once the investigative items are complete, the status of the event is marked as resolved. The data and history of the event is always available for all users to access and review Dominion 11 8/21/2012

18 Archived Investigations Used to determine have we had this same problem before? What did we do to correct it then. Have we had similar issues at other locations on the system? No need to reinvent the wheel here. Documentation of investigation and corrective action plan. Customer Inquiries 2012 Dominion 12 8/21/2012

19 Success of DIS Frequency of misoperations has decreased 21% in the past from 1997 to Our unknown causes has dropped by 50%. Number of automatic transmission operations has decreased 46% from 1997 to Dominion 13 8/21/2012

20 Operations Review and Risk Analysis Review all previous week operations with all stakeholders every Monday morning. Review identified risks and contingency plans for large load loss, customer count impact, and Key Accounts for upcoming planned work Dominion 14 8/21/2012

21 System Protection & Communications Working Group Review Monthly meeting to review identified relay protection, controls, protection communication issues/concerns with all stakeholders. Recommend actions or potential projects to address unique operations or system wide impacts Dominion 15 8/21/2012

22 Electrical Equipment Review Monthly meeting to review identified Electrical Equipment issues/concerns with all stakeholders. Document Issues, activities, and actions going forward in our Team Track database Dominion 16 8/21/2012

23 Safety = ZERO All meetings begin with a safety topic or thought for the day. Monthly review all Transmission accidents, incidents, as well as near misses Dominion 17 8/21/2012

24 Human Performance Tools Take Five Self Check Pre-Job Briefings Clear Communications Situational Awareness Questioning Attitude Peer Check Coaching Training and Qualifications 2012 Dominion 18 8/21/2012

25 Questions 2012 Dominion 19 8/21/2012

26 Reliability Risk Management Mike Moon, Senior Director of Reliability Risk Management December 12, 2012

27 Agenda Valued outcomes 2013 Strategic Goals Event Analysis Program Hurricane Sandy 2 RELIABILITY ACCOUNTABILITY

28 RRM Valued Outcomes ERO is aware of all bulk power system (BPS) events above a threshold of impact All reportable events are analyzed for sequence of events, root cause, risk to reliability, and mitigation Reporting and analysis are consistent to allow wide area assessment of trends and risks Industry is well informed of system events, emerging trends, risks analysis, lessons learned, and expected actions ERO is tracking industry accountability for critical reliability recommendations During crisis situations, ERO facilitates sharing of information among industry, Regions, and government 3 RELIABILITY ACCOUNTABILITY

29 2013 Goals Strategic Goal Area: Risks to Reliability Goal 4 Identify the most significant risks to reliability. Goal 5 Be accountable for mitigating reliability risks. Goal 6 Promote a culture of reliability excellence. 4 RELIABILITY ACCOUNTABILITY

30 EA Program Integrate industry efforts in analysis Event Analysis Subcommittee (EAS), Trending Working Group (TWG), Energy Management System (EMS) Task Force are Critical Improve entity event report quality Empower entities to also conduct cause analysis Share information Give credit to entities 5 RELIABILITY ACCOUNTABILITY

31 EA Program 247 categorized events reported to date (25 October November 2012) Cat Cat 2 78 Cat 3 10 Cat non categorized event reports 194 of 247 Cause Coded 79 percent 34 Lessons Learned Published 372 people trained; 112 registered entities, 8 Regions 6 RELIABILITY ACCOUNTABILITY

32 Incentives for EA Process Enable better event analysis with incentives to improve event reports: Lessons learned as part of continuing education hours (CEH) credit for System Operators Recognition of registered entities for quality and timely Event Analysis (EA) reports 7 RELIABILITY ACCOUNTABILITY

33 Next Steps Structured, predictable training program Regional and Registered Entity training Train-the-Trainer program Enhance EA Program Provide industry EA results and EA reports Southwest Blackout review now part of Lessons Learned training (approved for CEH credit) Providing data analysis to support Reliability Issues Steering Committee (RISC) efforts 8 RELIABILITY ACCOUNTABILITY

34 Hurricane SANDY EA Analysis of Hurricane SANDY impact on the BPS Preparation Operations during the event Restoration Superb communication: PJM, NYISO, ISONE, NPCC, RFC, NERC and federal agencies 9 RELIABILITY ACCOUNTABILITY

35 Michael Moon Questions EA Process Documents: RELIABILITY ACCOUNTABILITY

36 The Character of Harms Harms Avoid Pick important problems and fix them. Dr. Malcolm Sparrow John F Kennedy School of Government Severity High Impact Low Frequency (e.g. cyber ) Learn and Reduce Inverse Cost-Benefit Reporting Threshold Frequency 11 RELIABILITY ACCOUNTABILITY

37 Current NERC Priorities Relay mis-operations Right-of-way maintenance Vegetation Other clearances Human error Situational awareness Effective communications Cold weather preparation Critical infrastructure protection Solar magnetic disturbances Experience based High impact low frequency 12 RELIABILITY ACCOUNTABILITY

38 NPCC Review of Special Protection Systems NERC Operating Committee December 12 and 13, 2012

39 NPCC Directory 7, Special Protection Systems NPCC Classification of Special Protection Systems NPCC Design Criteria NPCC Review of New or Modified Special Protection Systems

40 NPCC Classification of Special Protection Systems Type 1---recognizes or anticipates abnormal system conditions resulting from design and operating criteria contingencies, and whose misoperation or failure to operate would have a significant adverse impact outside of the local area Type 2---recognizes or anticipates abnormal system conditions resulting from extreme contingencies or other extreme causes, and whose misoperation or failure to operate would have a significant adverse impact outside of the local area Type 3---no significant adverse impact outside the local area

41 NPCC More Stringent Design Criteria Section General Design Principles Special Protection System shall be designed to avoid false operation while itself experiencing a credible failure Special Protection System is capable of performing its intended function while itself experiencing a single failure Sections Specific Equipment Design Criteria Section Breaker Failure Protection Section Testing and Maintenance Section Performance Analysis

42 NPCC SPS Review Process Appendix B, Procedure for Review of Special Protection Systems Coordinated Technical Review by Task Force on Coordination of Planning (TFCP) Parallel Assessments by the Task Forces on System Studies, System Protection and Coordination of Operation Summary Report and Recommendation by the TFCP to the NPCC Reliability Coordinating Committee (RCC) Approval of the Special Protection System by the RCC

43 Relay Familiarization

44 Two Methods Classroom Training SME instructor Testing Self-paced Intranet Training Pre-test Discussion Embedded Videos Post-test

45 Intranet-based study

46 Intranet-based study

47 Classroom Training-Objectives Identify the fundamentals of system protection. Define the construction and operation of system protection. Identify the types of relays. etc.

48 Classroom Training Example Slides

49 Relay Classification Monitoring Auxiliary Programming Regulating Protective

50 Generation Power System Faults Transmission Distribution GSU Distribution Transformer Load Return Path

51 Questions 1. What is the purpose of auxiliary relays? 2. What is the purpose of protective relays? 3. When we refer to the selectivity of a relay, what are we referring to? 4. What is the most common type of fault on the power system? 5. What is the most severe type of fault on the power system?

52 Using the Numbering System CT 87B CT CT CT CT 21 67G 87T

53 Differential Relay Current Into Zone Fault X Protected Zone Current Out of Zone CT 87 CT Current Into Protected Zone

54 Steve Ashbaker Director Operations NERC Operating Committee December 12, 2012 Atlanta, GA

55 Background May 1 FERC/NERC Inquiry Report issued o 27 Recommendations in 8 categories June 10 Issued survey to identify actions underway July 20 Published survey results July 26 Received letter from Gerry Cauley o Identified 8 systemic or institutional concerns September 28 Submitted Response Report to NERC October 31 Launched September 8 webpage and Monthly Progress Dashboard 2

56 WECC Survey June 2012 WECC conducted a detailed survey on: Next-Day Studies Seasonal Planning Near- and Long-Term Planning Situational Awareness Consideration of BPS Equipment Protection Systems Angular Separation Survey results published on July 20 including identified gaps and best practices 3

57 WECC s Comprehensive Response Five WECC Focus Areas Organizational Operations and Planning Reliability Coordination Compliance NERC 4

58 Communications Initially, weekly calls between WECC, NERC, and FERC Now, semi-monthly calls with WECC, NERC, and FERC Launched September 8 webpage Implemented monthly progress dashboard September 8, 2011 Outage Event Response 5

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61 Key Accomplishments RC 8 Published next day studies to all signatories of UNDA Enhanced SOL/IROL methodology, now working on phase II Published Monitoring of Real-Time SOL and IROL Exceedance procedure Completed phase I of sub-100kv analysis RC Taskforce to review staffing, training, and tools

62 Key Accomplishments Operations Draft Guidelines approved and will be posted for comment o Next Day Study o Protection System Loadability o Real-Time Data Sharing o Real-Time Tools OC approval expected in January 9

63 Key Accomplishments Planning Increased awareness of WECC practices o Education related to Path concept o Education related to RAS Validation of models between operations (RC) and planning models (base cases) 10

64 Recommended NERC Activities NERC1 - Contingency Analysis NERC2 - Sub-100-kV Elements NERC3 - Parameters for Simulations NERC4 - Adequate Real-time Tools NERC5 - Notification of Loss of RTCA NERC6 - Sub-100-kV Relays NERC7 - Determination of Phase Angle Differences 11

65 Recommended NERC Activities NERC8 - Generator Validation Standard Drafting Team NERC9 - Review TOP-003 NERC10 - SAMS review Generator Control Issues NERC11 - Consider De-registration Process NERC12 - Consider Planning Coordinator Registration Gap Issues 12

66 Questions? Steve Ashbaker Director Operations

67 Balance Authority Reliability-Based Control Standard Drafting Team Update NERC Operating Committee December 13, 2012

68 Current Status BARC SDT BARC SDT was moved to active status July 2011 Limited scope to address changes to Balancing Standards that supported Frequency Response SDT initiatives BARC SDT Current Scope Proposed BAL-012, Operating Reserves Policy Modifications to BAL-001, Real Power Balancing Control Performance Modifications to BAL-002, Disturbance Control Performance Proposed BAL-013, Large Loss of Load Performance BAL-012 was posted for comment and ballot on 11/30/12 BAL-013, BAL-001, BAL-002 should be posted mid-december for comment and ballot 2 RELIABILITY ACCOUNTABILITY

69 BAL-012, Operating Reserves Planning Proposed new standard that requires BA or RSG to document its operating reserve plan Regulating reserves Contingency reserves Frequency response reserves Definitions sections has been clarified based on comments The SDT does not want the standard to be a documentation standard but a performance standard The standard has been simplified and focuses on requiring BAs to have a policy for different types of Operating Reserves The standard is not prescriptive in nature, it allows the BA to state a policy that is based on its system load and generation characteristics Relates to BAL-001, BAL-002 and BAL RELIABILITY ACCOUNTABILITY

70 Continent-Wide Reserve Policy BAL-012 BAL-001 BAL-002/013 BAL-003 BAL-012 Reserve Planning BAL-001 Regulating Reserves BA-002/013 Contingency Reserves BAL-003 Frequency Responsive Reserves 4 RELIABILITY ACCOUNTABILITY

71 BAL-001, Real Power Balancing Control Revision to existing BAL-001 standard Retains Control Performance Standard 1 (CPS1) Adds the proposed Balancing Authority Ace Limit (BAAL) standard Retires Control Performance 2 (CPS2) Defines Reporting ACE the ACE values used to compute CPS1 and BAAL In R2 the drafting team changed the method of calculating BAAL from using 60 Hz to using scheduled frequency. This mainly reduces the adverse effects of Time Error Correction on smaller BAs. The SDT was in hopes that Time Error Correction would be eliminated which would make this a none issue. 5 RELIABILITY ACCOUNTABILITY

72 Balancing Authority ACE Limit (BAAL) Requires a BA to balance its resources and demand in real-time so its ACE does not exceed its BAAL limit for more than 30 consecutive minutes. BAAL limits (high and low) are unique for each BA. Based on BA frequency bias setting and its Interconnection Frequency Trigger Limit (FTL). FTL for each Interconnection were based on reliability studies and analysis FTL is that frequency threshold value which is three standard deviations (epsilon 1) from Frequency Scheduled. When all BA are within their BAAL the Interconnection frequency will remain within its FTL limits. 6 RELIABILITY ACCOUNTABILITY

73 Balance Authority ACE Limit (BAAL) Supporting Frequency BAAL High Hurting Frequency 1 ACE ( MW ) Y= Hurting Frequency BAAL Low Supporting Frequency Frequency (Hz) BAAL high and BAAL low curves are unique for each BA 7 RELIABILITY ACCOUNTABILITY

74 BAAL Versus CPS2 Control Performance 2 (CPS 2) Requires a BA to maintain its average one-minute ACE within its L 10 values measured every 10 minutes Not a function of frequency Can result in a BA correcting its ACE in a direction that would not enhance reliability Only requires 90 percent compliance, a BA can push or drag minute periods (72 hours) greater than its L 10 per month and be compliant. Often requires quick movement of expensive resources Balancing Area ACE Limit (BAAL) Based on Frequency Trigger Limits (FTL) which are unique for each Interconnection and a BA s bias setting (B) Provides a clear indication to a BA and its RC of when a BA must take corrective actions Always drives corrective actions in a direction that supports Interconnection frequency BAAL becomes more restrictive than corresponding CPS2 s L 10 as Interconnection frequency deviates from scheduled frequency Allows more efficient movement of resources Reduces the impact of non-conforming loads on BA performance 8 RELIABILITY ACCOUNTABILITY

75 BAL-002, Disturbance Control Performance Continues to address loss of resource o Generation resources o Loss of non-interruptible imports Several definitions are introduced to provide clarity o Most Severe Single Contingency (MSSC) o Reportable Contingency Event o Balancing Contingency Event o Contingency Event Recovery Period o Contingency Event Recovery Criteria DCS reporting threshold is proposed to be lesser of 80 percent of MSSC or 500 MW. Equations and detailed explanations on how to compute compliance has been moved to an attachment Requirements now in the Additional Compliance Information section have been moved to the Requirements section o Multiple contingencies, simultaneous contingencies, etc. 9 RELIABILITY ACCOUNTABILITY

76 BAL-002, Disturbance Control Performance Definitions: From the comments SDT was able to clean up the definitions 500 MW criteria came from meetings with Bob Cummings and data from Carlos Martinez. It represents a compromise for various Interconnections. Large loss of load was not included in BAL-002, but was separated from DCS for simplification and to allow separate voting (See proposed BAL-013) Compliance will be based on percent recovery on a per event basis The standard allows DCS events happening within a 105 minute period of time to have complementary treatment which does not penalize the BA 10 RELIABILITY ACCOUNTABILITY

77 BAL-013, Large Loss of Load FERC 693 directive required ERO to modify BAL-002 to define a reportable event to include loss of load. Existing BAL-002 standard explicitly excludes the loss of load. The BARC SDT felt it would be better to address the loss of load in a separate standard. Reporting threshold for large loss of load is equal to the lesser of the responsible entity s MSSC or 500 MW Recovery criterion is to return ACE to zero or its predisturbance value in 15 minutes. Compliance is based on any additional amount of time to recover after the first 15 minutes following the start of the event 11 RELIABILITY ACCOUNTABILITY

78 Thoughts for the OC If the ballot for BAL is affirmative, do we phase-in new entrants to the field trial until all BAs and RSGs are included, or are they on their own to become compliant by the implementation date? If the ballot for BAL fails, how and when do we unwind the field trial and revert participants to the existing BAL (CPS2)? Unwinding the field trail too quickly could negatively impact reliability 12 RELIABILITY ACCOUNTABILITY

79 Thoughts for the OC Does the OC like our approach on BAL-012 for fulfilling the FERC order requirements for a continent-wide policy on (contingency) reserves? What does the OC think of the 500 MW requirements in BAL and BAL-013? Does the BARC SDT need to provide a final report for the field trial or is regular updates and WebEx presentations sufficient? 13 RELIABILITY ACCOUNTABILITY

80 Questions? 14 RELIABILITY ACCOUNTABILITY

81 Reliability Considerations for BA Communications with Increased Variable Generation PC Meeting December 13, 2012

82 IVGTF Subgroup 2-2 Overview: Adequate communication of data from variable generation is not only a vital reliability requirement, but also such communications are necessary to support the data analysis posed by other recommended actions. The NERC Operating Committee should undertake a review of COM-002, FAC-001 and registry criteria to ensure adequate communications are in place. Further, as NERC Standards Project is reviewing COM-002, input to this review should be provided. If these standards are found to be inadequate, action should be initiated to remedy the situation (e.g. a SAR). 2 RELIABILITY ACCOUNTABILITY

83 IVGTF Subgroup 2-2 Objective: To ensure that Balancing Areas have sufficient communications for monitoring and sending dispatch instructions to variable resources. Review of NERC s Facilities Design, Connections and Maintenance, (FAC) Standard FAC to ensure that the following are addressed: o Establish appropriate interconnection procedures and standards; o Ensure adequate communications considering COM and registry Criteria; o Provide input to NERC Standards Project , 0 which is reviewing COM RELIABILITY ACCOUNTABILITY

84 IVGTF 2-2 Report Overview Explores practices in several areas (both market and non-market) Examines lessons learned from the November 4, 2006 European wind outage event Recommends new minimum requirements for wind farms generating above a specific threshold Proposes modification to six existing NERC Standards. 4 RELIABILITY ACCOUNTABILITY

85 Common Practices The following data and communication capabilities are already required in many markets and should be provided to the BA by all generation operating in the BA that has an impact on the reliability of the Bulk Electric System (BES): Net & Gross MW and MVar Meteorological Data Normal and emergency ramp rate capability Turbine availability Other modeling data Currently, most requirements are not applicable for a significant number of smaller wind farms (less than 75 MW) unless they are covered in the interconnection agreement or the market rules (if applicable). 5 RELIABILITY ACCOUNTABILITY

86 General Recommendations This report recommends that all generators 10 MW or greater within a BA (regardless of interconnection point) shall provide: Breaker status to the BA/TOP (FAC-001) Current MW and MVAR output (FAC-001) Voice circuit for communication of real time instruction (COM-002) Remote control of resources is adequate but should be capable of handling real time operational issues. Coordination of relay settings, specifically under-frequency coordination (FAC-001) 6 RELIABILITY ACCOUNTABILITY

87 Modification to NERC Standards Additionally, the following updates are recommended for existing NERC Standards: FAC-001: TO would list specific requirements for generation not only for generation connected to the transmission system but also any generation in the footprint that is within the area operated by the transmission area that will impact the operation of the Balancing Authority and Bulk Electric Transmission System. COM-002: Consider applying the standard to all generation 10 MW or greater. This improvement in communication will not only improve data communication but also require the generator operator to be available to address real time operational issues. This can be accomplished with manned resources or remote control and monitoring of the facilities. PRC-001: Under requirement 3, make this requirement applicable to facilities 10 MW or greater. This will ensure that the necessary relay coordination has taken place to reduce the reliability impact of un-expected relay operation, specifically operation of under and over frequency relays. The generation should be set lower that the under frequency load shedding relays in the region to ensure generation tripping does not compound under frequency operation similar to the European event. 7 RELIABILITY ACCOUNTABILITY

88 Report Recommendations TOP-001: Under requirement 3, require all generation facilities 10 MW or greater have to comply with reliability directives from the Balancing Authority or the Transmission Operator. Under requirement 7, all generation facilities 10 MW or greater provide notice to the Balancing Authority and the Transmission Operator before removing generation facilities from service to reduce the reliability impact to the system. TOP-002-2b: Under requirement 3, require all generation facilities 10 MW or greater to provide its current, next day, and seasonal operations with the host Balancing Authority and Transmission Provider. This will improve the reliability studies of the Bulk Electric system. TOP-003-1: For generation facilities 10 MW or greater require outage coordination of generation facilities including telemetering equipment and voltage regulation equipment so that interconnected operations is coordinated between Balancing Authorities, Transmission Operators, and Reliability Coordinators. 8 RELIABILITY ACCOUNTABILITY

89 Conclusion These changes should be reviewed and implemented in the next review cycle. Adding these requirements to the functional requirements with audit oversight will ensure the operators have the tools necessary for not only normal operations but also for abnormal operation and system restoration. Communications between BAs, Transmission System Operators, and plant operators will continue to play an essential role in reliably expanding the integration of variable resources. 9 RELIABILITY ACCOUNTABILITY