Renewables in Hawaii. Mr. Dick Rosenblum President and CEO Hawaiian Electric Company NERC Board of Trustees Meeting Phoenix, Arizona February 6, 2014

Transcription

1 Renewables in Hawaii Mr. Dick Rosenblum President and CEO Hawaiian Electric Company NERC Board of Trustees Meeting Phoenix, Arizona February 6, 2014

2 2 Hawaii is Different Each Island is an independent grid We have no one to fall back on Frequency excursions are common We have no traditional generation fuel sources Our traditional generation has been petroleum-based We do have generous renewable resources Goal to reach 40% renewables by 2030 We are already at 18% Renewables are cost effective If we procure them successfully 10% of customers have DG (PV) NEM rates provide 2-3 year payback 30% Fed., 35% State and NEM We use load shed schemes for extreme events Used to have island-wide blackouts

3 Hawaiian Electric Service Area and 2013 Data 100% Market Share for 95% of state: 3 utilities, 5 separate grids 3 Kauai Oahu Maui Electric System peaks: 190 (Maui Island) 5.4 MW (Molokai) 5.0 MW (Lanai) Renewable generation 1 : 30% Molokai Maui Hawaiian Electric System peak: 1,144 MW Renewable generation 1 : 11% Hawaii 1 As a percentage of total sales Hawaii Electric Light System peak: 190 MW Renewable generation 1 : 49%

4 The Situation on Each Island is Different % Renewable Generation Through November Oil 71.30% Renewable 10.46% Coal 18.24% Biofuel 0.37% Solar 3.54% Waste to Energy 4.88% Wind 1.67% Oil 56.93% Renewable 43.07% Geothermal 23.13% Solar 4.15% Wind 12.66% Hydro 3.13% Oahu: 5.21% Variable Renewable Hawaii 19.9% Variable Renewable Solar 3.97% Oil 72.62% Renewable 26% Hydro 0.61% Wind 18.84% Coal 0.92% Biomass 3.04% Maui 23.42% Variable Renewable

5 Cumulative Installed PV (Hawaiian Electric Companies), MW Continued High Growth of PV in Hawaii % of circuits are already over 100% of their Daytime Minimum Load (DML) Aggregate peak load of all islands combined is about 1,550 MW

6 Renewable Energy % (RE/Net Gen) Renewable Generation Is a Significant Portion of Energy 6 80% Hawaii Electric Light Renewable Energy Percentage "Duration Curve" % 60% 50% 40% 30% 20% 10% 0% Hours in 2013

7 Renewable Energy % (RE/Net Gen) Variable Generation Is a Significant Portion of Energy 7 80% Hawaii Electric Light Wind, Solar & Hydro Energy Percentage "Duration Curve" % 60% 50% 40% 30% 20% 10% 0% Hours in 2013

8 Typical Renewable Contribution (Oahu: July 28, 2013) Impact of Rooftop Solar Wind Dip and Surge 8

9 Renewables During Tropical Storm Flossie (Oahu: July 29, 2013) 9 Impact of Rooftop Solar Wind shuts down in high wind regime

10 The Duck is Almost Here (Oahu January 22, 2014) 10 Cold and Sunny Day

11 What s Changing Theory on the Mainland is Reality in Hawaii 11 Generation Baseload and mid-merit driven off system Replaced with fast-start, fast-maneuver generation Significant generation is not visible or controllable (PV) Transmission Transients are magnified Sympathetic tripping of PV at high or low frequency Transients are accelerated Loss of inertia Less generating units to control transients Control measures are degraded UFLS reduced and variable due to DG Frequency instability Distribution Voltage variations Load rejection overvoltage Islanding Protection effectiveness Distributed solar could displace lower-cost wind energy in 2014 (Hawaii Island)

12 Mahalo!

13 Generation (MW) 20 Wind Impacts on Reserves (Hawaii Island) Wind Ramp Impact to System Hawaii and Maui islands operate with very low online reserve as fuel cost savings - when wind output is steady. Here, a wind ramp down after a period of steady output utilized all online reserves. HRD KAMAOA REG UP 4 2 Reserve near zero due to wind 0 12:00 12:15 12:30 12:45 13:00 13:15 13:30 13:45 14:00 14:15 Thursday, February 21, 2013

14 Use of Fast-Start Diesels - Wind Ramp 14 Hawaii Island Sudden downramp in wind (green) during morning load rise Frequency drop due to wind reduction Frequency restored by bringing on diesels (blue)

15 Fast Variability Frequency Impact Mitigated by Curtailment 15 Frequency oscillations (dark blue) caused by wind (yellow) - reduced by curtailing wind plant

16 Sunny, clear day = less demand on circuit for UFLS 16

17 Backup Slides Mr. Dick Rosenblum President and CEO Hawaiian Electric Company NERC Board of Trustees Meeting Phoenix, Arizona February 6, 2014

18 Change in Generation Mix Impacting System Reliability and Security Dispatchable, frequency responsive generation displaced to accommodate variable generation. Cycled offline or operated near minimum dispatch Increased rate of change of frequency Lower Nadir (frequency low point) and/or Additional Load-shed Increased average frequency error Potential voltage limit violations/ voltage instability Planning must identify generation operators need to maintain acceptable system security Requires modeling of variable gen impacts, including DG Individual gen models become very important in simulations Reduced security margins from historical operation Individual unit performance becomes critical to system response Customers could see more outages Post-disturbance review important to verify system performance Continue improved dynamics modeling through tests, real-time monitoring, PMU s 18

19 Impacts on Frequency Control / System Balancing for Island Grids Disadvantages of island systems All imbalance between generation and demand results in frequency error (no interchange) Single facility can have large influence on frequency, due to small system size Small frequency bias (can be 2-3 MW/.1 Hz on Maui and Hawaii) Limited ability to leverage geographic diversity to mitigate variability Operated closer to security constraints than most power systems Faults cause frequency/voltage deviations beyond typically experienced on mainland risk of large aggregate loss of gen from distributed generators Wind/solar PV difficult to forecast due to variable weather patterns Advantages of island systems No market operators have direct control of generating assets which maximizes operational flexibility: not constrained by market rules or design Generating resources used for peaking/emergency conditions on the islands provide flexible resources useful for variable generation (fast-start generating units) 19

20 Mitigation of Impacts on Frequency Control / Balancing Increased dispatchable gen operating range, ramp rates Measure/correct governor droop response for critical dispatchable generators to design (4-5%) Modifications to AGC to improve frequency control with wind generation Online Reserve modifications maintain online reserves for increased ramping and regulation requirements dynamic requirement based on observed variability and amount of variable gen Fast-starting generation used to mitigate unexpected ramp events 20

21 Measures Taken to Improve System Security/Frequency Control Interconnection requirements for all trans. connected gen including wind, large solar, and geothermal Droop, inertial response, ramp rate, voltage regulation voltage regulation, expanded disturbance ride-through requirements (reflecting island grid conditions) Active power control (curtailment) used routinely to avoid excess energy during lower-demand periods Used to smooth excessive variability Ramping control both up and down for wind plant (Maui Electric) Modified underfrequency Load shed schemes required for system dynamic behavior with new generation mix Tripping time reduced from 19 to 8 cycles on Hawaii island A time-delay block added for ramp-type contingencies (loss of combine cycle gas turbine or wind ramps) Fewer blocks, larger amount shed to restore closer to normal frequency Future: Measures to manage High Penetration of Distributed Gen Interconnection requirements for DG expanded ride-through, frequency response, voltage control (discussed more later) Dynamic Load-shed scheme (discussed more later) 21

22 22 Active Power Control needed for DG Island systems have significant amounts of must-take renewable generation (wind, hydro, geothermal) Excess energy conditions routinely occur during off-peak hours DG at forecast levels will force daytime curtailment and may force dispatchable units below minimums Island systems more vulnerable to system failure Once a portion of system is reenergized, DER will reconnect If a restoration is needed during high solar production, it will be difficult to balance the system (already a difficult task) Where feasible, communication and control by interfacing to DG relays from nearby sub RTU is being deployed

23 DG Behavior during Disturbances Impacting System Security Connecting DG are now required to use 57 Hz trip setting (but does not guarantee ride-through) Legacy DG trip at 59.3 Hz IEEE 1547 default Recent daytime generator trip on Oahu, MW of PV tripped. Estimates based on different methods; using solar data and system response Increased largest contingency by 27-36% Over frequency trip settings are also critical Loss of PV occurring for transmission faults under normal clearing on Oahu, resulting in low-frequency 23

24 DG Behavior During Voltage Disturbances Undervoltage trip setting is also a concern Island systems experience momentary wide-spread low-voltages during faults and contingencies Aggregate loss of DER may exacerbate conditions when disconnecting for low voltage (effectively increasing load during low voltage) Need to determine the voltage ride-through requirement at distribution level Ride-through requirements will help mitigate system impacts but may require mitigation of risk for circuit island detection settings must be a balance of circuit and system needs 24

25 Voltage Ride-Through 25

26 DG Impact on Underfrequency Loadshed Effectiveness Island systems rely heavily on underfrequency load-shed (UFLS) for loss of generation contingencies Distributed Solar PV cause circuit load to vary significantly throughout the day DER loss offsets effective load reduction from shedding UFLS circuits Illustrated on next slide 26

27 Impact on Underfrequency Loadshed Scheme More circuits (and customers) being shed than in the past for the same generator contingency For higher levels, scheme may be insufficient to prevent system failure Dynamic scheme may be necessary to reflect impact of DG on amount of load available Need to determine largest contingency including contribution from DER Requires aggregate estimate of DER production UFLS relays be would set based on actual circuit net demand Some circuits may export during high PV production UFLS need to be blocked when circuit exporting 27

28 Operations Impacts from Changes in Net Demand Net demand more variable, less predictable Beginning to integrate wind and solar forecasting into operations Two peaks (morning and evening) with valley in the middle caused by increased distr. PV Changes types of units needed Cycling, quick start, fast ramping, able to operate short periods (small minimum up / down times) Units historically operated continuously may need to cycle offline to avoid excessive costs by operating at inefficient levels Cycling capabilities and costs being studied 28

29 29 Demand Forecasting Wind and Solar Impacts on Demand Less predictable net demand makes it difficult for operators to decide when to start up and shutdown generators increases costs Forecasting is more critical as more units historically operated continuously are cycled offline Island systems must balance system at all times imbalance = frequency error Today: Adjusting commitment using existing tools Adjust online reserves for real-time observed variability Solar models incorporating connected PV are being tested Wind forecast models were constructed for specific windfarm sites and are also being tested by operations Future: Improve weather forecasting models and tools Need to develop day-ahead unit commitment tools to incorporate the forecasts to facilitate offline cycling Real-time production and availability data would improve forecasts

30 System Load (MW) Estimated PV (MW) PV Ramp Event Impact on Net Demand PV Load Ramps Sys_Load Est_PV :00 10:00 11:00 12:00 13:00 14:00 15:00 Sunday, December 2, 2012

31 11:25 11:26 11:27 11:28 11:29 11:30 11:31 11:32 11:33 11:34 11:35 11:36 11:37 11:38 11:39 11:40 11:41 11:42 11:43 11:44 11:45 11:46 11:47 11:48 11:49 11:50 Gerneration (MW) System Frequency (Hz) 31 Wind Variability 20 Wind Ramp Event Kamaoa Ramp down/up KAMAOA_GEN_(MW) DIESELS BESS_MW FREQUENCY Thursday, January 24, 2013 Wind down ramp on the Hawaii island system resulted low frequency. Diesels were used to restore frequency. Wind ramped back up following the event.

32 Daily PV Impact on Net Demand Monday Through Sunday - Hawaii Island 32 Red line: measured net system demand (customer demand PV) Blue line: estimated customer demand without reduction from PV Estimated Solar Production

33 Molokai Day Demand Lower Than Night Minimum Due to PV 33

34 34 Estimating PV Production Measured data from production required to tune solar production forecasting and for operators to understand changes in net demand Approximation technique is being used based on solar irradiance monitors, scale by nearby capacity This method has improved visibility This method creates administrative burden to update rapidly increasing installed capacity

35 Recent snap-shot of Hawaii Island overview display. Colored circles indicate PV level. PV estimated to provide 17% of total demand (161.2 MW) 35

36 36 Summary of Actions Challenges of distributed generation are more difficult than transmission-connected generation due to 1547 rules and large number of small participants Planning for Operational Configurations to Maintain System Security Include DG in system planning models Need for tools to allow rapid updates Identify combinations of generation that should be able to provide acceptable system security through network security analysis Implement system changes such as modified UFLS scheme, dynamic UFLS scheme Interconnection Requirements to maintain System Security and Operability Active power control Ride-through Voltage control Needed for Distributed Generation as amounts are equivalent or exceed largest transmission generator Develop Operator Controls and Tools Identify the minimum online generation for system security Forecasting tools and Unit commitment incorporating forecast uncertainty (day ahead, updates) Real-time Visibility and Control for Aggregate Variable and Distributed Gen Flexible Generation: Fast starting Generation and/or Demand Response, faster ramp rates, cycling capability, larger dispatch range Review system behavior post-disturbance, identify any new concerns or problems and improve system models (PMU data useful) studies cannot identify all potential issues! Need operational experience.

37 Hawaii Island 2013 Total Generation by Type (Does not include self-generation from NEM, load offset) 37 diesel 0.7% simple cycle gas turbine 0.7% run of river hydro 3.0% combined cycle 36.7% Other 40.5% geothermal 24.3% steam 21.4% wind 13.1% FIT/CSP 0.1%

38 Renewable Energy % (RE/Net Gen) 38 70% Maui Electric Company - Maui Division Wind & Hydro (no Solar) Energy "Duration Curve" % 50% 40% 30% 20% 10% 0% Hours in 2013

39 DG Exponential Growth: 39 Engineering/Planning Challenge Standard Distribution Interconnection Process Screening focuses on distribution feeder-level issues No trigger for system level/ area level network analysis based on aggregate impacts No defined mechanism to disallow projects contributing to area or system level reliability problems Growth is faster than system studies and development of mitigation measures and operator tools

40 % Renewable Generation Through November 2013 RE Generation includes non-utility selfgeneration from FIT, NEM, and Rule 14H.

41 Standards Mark Lauby, Vice President and Director of Standards Board of Trustees Meeting February 6, 2014

42 Coordinate Interchange Standards Reliability Benefits Make transactions more transparent for reliability assessments Clarify which functional entities perform Interchange Authority tasks Action Adopt five standards and associated definitions o INT Dynamic Transfers o INT Evaluation of Interchange Transactions o INT Implementation of Interchange o INT Interchange Initiation and Modification for Reliability o INT Intra-Balancing Authority Transaction Identification 2 RELIABILITY ACCOUNTABILITY

43 Operations Personnel Training PER Reliability Benefits Personnel performing or supporting reliable Real-time operations of the Bulk Electric System are sufficiently trained, using a systematic approach Action Adopt PER Operations Personnel Training and associated documents 3 RELIABILITY ACCOUNTABILITY

44 Available Transmission System Capability MOD Reliability Benefits Focuses on the reliability aspects of Available Transmission Capability (ATC) and Available Flowgate Capability (AFC) determinations Supports ATC and AFC information sharing for reliability purposes Action Adopt MOD Available Transmission System Capability and associated documents 4 RELIABILITY ACCOUNTABILITY

45 Modeling Data MOD and MOD Reliability Benefits Framework to support the development of planning models Establishes consistency in data requirements and reporting procedures Supports data validation Action Adopt MOD Data for Power System Modeling and Analysis, MOD Steady-State and Dynamic System Model Validation, and associated documents 5 RELIABILITY ACCOUNTABILITY

46 Voltage and Reactive Control VAR Reliability Benefits Ensures voltage levels and reactive flows are monitored Requires adequate voltage support to be scheduled and System Operating Limits avoided Study data provided supporting voltage schedules and tolerance bands Action Adopt VAR Voltage and Reactive Control and associated documents 6 RELIABILITY ACCOUNTABILITY

47 Operating Personnel Communications Protocols - COM COM posted January 2, 2014 Thirty-day comment period using Standards Committee wavier Ten-day concurrent ballot Ballot ended January 31, 2014 Results of ballot Summary of comments received 7 RELIABILITY ACCOUNTABILITY

48 Readopt Standards Reaffirmed by Periodic Review Reliability Benefits Periodic review goal: Evaluate whether Standards remain pertinent; identify necessary improvements Review used technical, Paragraph 81, and quality and results-based criteria Action Readopt four standards: o FAC Transmission Vegetation Management o FAC Facility Ratings o FAC Assessment of Transfer Capability for the Near-term Transmission Planning Horizon o IRO Reliability Coordination Transmission Loading Relief 8 RELIABILITY ACCOUNTABILITY

49 Unit Auxiliary Transformer (UAT) Drafting team response to Board of Trustee s request to assess reliability concerns from UAT low-voltage relay loading: Unresolved minority comment in the Reliability Standard: Relay Loadability: Generation (PRC-025-1) adopted in August 2013 Analysis indicates: o No reliability gap results from excluding low-voltage UAT relays o Reveals relay loadability within margins employed by industry o Recommends monitoring as a first step to reveal outages in the future o Report available on the project page under Related Files Action - Information Only: Engage Generating Availability Data System WG to determine data needs Address any identified risk through normal risk analysis processes 9 RELIABILITY ACCOUNTABILITY

50 WECC Interpretation of TOP-007-WECC-1 Clarification The regional Reliability Standard only applies to Transmission Operators (TOPs) and does not apply to Path Operators Action Adopt the WECC interpretation of TOP-007-WECC-1 requested by Arizona Public Service (APS) and authorize staff to file with applicable regulatory authorities 10 RELIABILITY ACCOUNTABILITY

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52 GridEx II Post Exercise Update Matt Blizard, Director of Critical Infrastructure Department Board of Trustees Meeting February 6, 2014

53 GridEx II Objectives GridEx II was a successful exercise based on the lessons learned from GridEx 2011 The exercise focused on: Exercising cyber and physical crisis response Increasing information sharing Gathering lessons learned Discussing a more severe event scenario at an executive level 2 RELIABILITY ACCOUNTABILITY

54 GridEx II Scenario Escalation Timeline 3 RELIABILITY ACCOUNTABILITY

55 Distributed Play Participation GridEx 2011 had 420 compared to GridEx II with 2,000 individual participants 4 RELIABILITY ACCOUNTABILITY

56 Industry-Wide Coordination Electricity Sector Information Sharing and Analysis Center (ES- ISAC) and NERC s Bulk Power System Awareness (BPSA) saw increased communication Still room for improvement on information sharing Both coordinated with Department of Energy, Department of Homeland Security, and Federal Energy Regulatory Commission to deliver response to industry Four joint sector conference calls Five NERC-internal Crisis Action Team calls Thirteen Watch List postings Three NERC Alerts released o One Advisory Alert (Level 1) o Two Recommendation Alerts (Level 2) 5 RELIABILITY ACCOUNTABILITY

57 Lessons Learned Distributed Play 1. Information sharing has increased 2. NERC has improved ES-ISAC and BPSA coordination functions 3. Simultaneous cyber and physical attacks pose significant challenges 4. Industry continues to refine and enhance its all-hazard incidence response plans and protocols 5. Industry and government information sharing stakeholders can better inform incident response through coordination and consolidation of content 6 RELIABILITY ACCOUNTABILITY

58 Recommendations Executive Tabletop There were 10 recommendations in four broad areas of interest: Information Sharing between the Electricity Industry and Government o Situation assessment scalability o Public communications Operational Decision Making o Unity of Effort o Cyber attacks create unique restoration challenges o Physical attacks create unique restoration challenges o Mutual aid and critical spares 7 RELIABILITY ACCOUNTABILITY

59 Recommendations Executive Tabletop There were 10 recommendations in four broad areas of interest: Legal and Regulatory Authorities o Regulatory relief o Implementing emergency legislation Next Steps o Acting on the recommendations o Planning future exercises of this nature 8 RELIABILITY ACCOUNTABILITY

60 Next Steps GridEx II Distributed Play Report Anticipated that individual entities, NERC Critical Infrastructure Protection Committee, and other industry forums will consider and act on the recommendations GridEx II Executive Tabletop Recommendations provide several opportunitiues to enhance industry and government coordination Discussed at January 30, 2014 Electricity Sub-sector Coordinating Council (ESCC) meeting Reports will be published mid to late-february 9 RELIABILITY ACCOUNTABILITY

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62 Status of 345kV Circuit Breaker Alert Follow-up Tom Galloway, CEO, North American Transmission Forum Michael Moon, Senior Director, Reliability Risk Management, NERC Board of Trustees Meeting February 6, RELIABILITY ACCOUNTABILITY

63 Background Trend in 345kV Circuit Breaker identified Research confirmed risk NERC staff and Event Analysis Subcommittee briefed NERC Operating Committee (OC) NERC Member Representatives Committee (MRC) Discussion at August MRC and Board of Trustees (Board) Meetings NERC CEO directed Level 1 (Advisory) Alert NERC CEO requested support from Forums to determine extent of condition Reliability risk to monitor in 2014 Closure based on final report at August 2014 Board meeting 2 RELIABILITY ACCOUNTABILITY

64 Status North American Transmission Forum (NATF) leading collaboration efforts with North American Generator Forum (NAGF) and Trades Breakers accounted for 791 of the 1000 Failures (all) 24 Failures (nozzle and torque) 7 Inspected 531 Maintenance performed 297 Nozzle replaced 220 Asset owners continue assessment and maintenance planning Additional information in NATF report mitigates further risk Final report to Board at August 2014 meeting 3 RELIABILITY ACCOUNTABILITY

65 Tom Galloway CEO, NATF office cell Michael Moon NERC, Senior Director, Reliability Risk Management office cell 4 RELIABILITY ACCOUNTABILITY

66 Staging of High-Priority Risk Projects and Reliability Assessments Thomas Burgess, Vice President and Director of Reliability Assessments and Performance Analysis Board of Trustees Meeting February 6, 2014

67 Reliability Risk Management Process RISC Input Technical Committee Input Guidelines Training! R A P A State of Reliability Report LTRA and other Assessments Strategic Plan, BP&B Projects and Work Plans Alerts Data Requests Event Analysis Reliability Leadership Summit, Other Input? Others? Technical Conferences Standards 2 RELIABILITY ACCOUNTABILITY

68 ERO Top Priority Reliability Risks Top Priority Risks emerged from diverse inputs: Risk Management Projects: Changing Resource Mix Resource Planning Protection System Reliability Uncoordinated Protection Systems Extreme Physical Events Availability of Real-time Tools and Monitoring Protection System Misoperations Monitoring Stage Activities: Cold Weather Preparedness Right-of-Way Clearances 345-kV Breaker Failures 3 RELIABILITY ACCOUNTABILITY

69 Reliability Risk Management Project Activities for 2014 Selected Reliability Risk Management Projects to measure ERO performance in mitigating reliability risks: Changing Resource Mix Threshold: Essential Reliability Services (ERS) whitepaper Target: Phase 1 ERS Special Assessment to Board Resource Planning Threshold: Meetings with regulators Target: Action taken to address Extreme Physical Events Threshold: Industry-approved Geomagnetic Disturbance (GMD) Standard Target: Filed GMD Standard Protection System Misoperations Threshold: Industry-approve Misoperations Standard Target: Filed Misoperations Standard 4 RELIABILITY ACCOUNTABILITY

70 Reliability Risk Monitoring Activities for 2014 Selected Risk Monitoring activities with continuing efforts to measure ERO effectiveness in mitigating reliability risks: Cold Weather Preparedness Threshold: Guideline implementation verification Target: Reduced loss-of-load events due to cold weather Right-of-Way Clearances Threshold: Analysis complete Target: 95 percent of entities with verified or updated ratings 345-kV Breaker Failures Threshold: Reports to Board in February and August Target: Increased time between failures 5 RELIABILITY ACCOUNTABILITY

71 Long-term and seasonal reliability assessments Three annual reports Long-Term, Summer, Winter Enhanced with probabilistic metrics Aligned to consider emerging issues Performance analysis of key reliability indicators Annual State of Reliability Report Integrate with event analysis results Special Reliability Assessments - focus areas Reliability Assessment Essential Reliability Services, assessment, and recommendations Reliability impacts of emerging environmental initiatives Focused special assessment on resource adequacy planning GMD assessment and guidelines to aid in standard development 6 RELIABILITY ACCOUNTABILITY

72 Adopt staging of reliability assessments approach Inputs and factors: Long-term and seasonal reliability assessment conclusions Performance Analysis of key reliability indicators trends Reliability Risk Management insights and priorities Technical and Member Representatives Committees Emerging risks and potential impacts Significant anticipated policy or regulatory initiatives Special Reliability Assessments - Select strategic areas of focus Align prioritization and significance Manage resources and deliverables Refresh at least annually Reliability Assessments RELIABILITY ACCOUNTABILITY

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74 Reliability Issues Steering Committee Report Bob Schaffeld, RISC Chair Board of Trustees Meeting February 6, 2014

75 Reliability Risk Management Process RISC Input Technical Committee Input Guidelines Training! R A P A State of Reliability Report LTRA and other Assessments Strategic Plan, BP&B Projects and Work Plans Alerts Data Requests Event Analysis Other Input? Others? Technical Conferences Standards 2 RELIABILITY ACCOUNTABILITY

76 NOVEMBER MARCH JUNE SEPTEMBER OCTOBER FEBRUARY SEPTEMBER DECEMBER AUGUST JANUARY Reliability Risk Management Process ERO Planning Timeline 2013 LTRA Review State of Reliability Report Review Reliability Leadership Summit RISC Priorities to Board Risk Management Strategies Proposed ERO Top Priorities Filing Of BP&B Project Kick-Offs 20XX 20XX+1 20XX+2 RISC performs evaluation and prioritization of risk areas NOTE Planning cycles overlap, but are not shown for reading ease. RISC and Committees analyze risks areas and recommend management strategies for specific reliability risks Staff assembles input and drafts Top Priorities; RISC reviews; Results included in Strategic Plan Iterative process for development of BP&B, including specific section on reliability risk management projects Committee and staff detail projects immediately prior to execution 3 RELIABILITY ACCOUNTABILITY

77 Planned 2014 Activities Align RISC deliverables with Reliability Risk Management Process (RRMP) and Business Plan and Budget development schedule Work with the Technical Committees to review ERO Top Priorities document Hold Reliability Leadership Summit in Fall (September/October) Collect information, begin development of RISC Priority Recommendations for delivery to the Board February RELIABILITY ACCOUNTABILITY

78 Planned 2014 Activities Review and Evaluate Charter Charter: Member Representatives Committee (MRC) reviews at first anniversary of RISC and every third year thereafter August 2013: no changes recommended Since August: process concepts shared with the Operating Committee (OC), Planning Committee (PC), Critical Infrastructure Protection Committee (CIPC), Compliance and Certification Committee (CCC), Standing Committee (SC); progress made on finalizing time lines and ensuring repeatability Plan to review Standards Process Input Group s (SPIG s) expectations, experiences, and areas for improvement 5 RELIABILITY ACCOUNTABILITY

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