Read Thursday March 11, 2010 text version

SERC Reliability Corporation Operating Committee (OC) MEETING AGENDA October 14, 2010; 1 ­ 5 PM October 15, 2010; 8 AM ­ 12 Noon Biloxi, MS

1. Call meeting to order A. General comments, arrangements, evacuation procedures B. Introduction of members and guests C. Announcement of quorum D. SERC Confidentiality Policy E. SERC Antitrust Guidelines F. Agenda ­ approval required G. SERC action items from May 26, 2010 meeting H. May 26, 2010 meeting minutes ­ approval required I. Nominating Committee J. Aurora Alert 2. Discuss NERC/SERC general topics A. Compliance follow-up B. CIPC Compliance, Registration & Certification follow-up C. NERC OC meeting ­ September 14-15, 2010 D. OATI Scheduling/Checkout Tool ­ progress report E. Report on Metrics Task Force F. NERC EAWG ­ Update G. SERC OC three year Work Plan H. NERC Aurora Break (refreshments) 3. Situational awareness update 4. Events analysis update 5. SERC Triage Team on FERC orders 6. Discuss SERC subcommittee topics A. Operations Planning Subcommittee (OPS Approval required for following: SERC Disturbance Reporting Procedure EOP-004-1 SERC Contingency Reserve Policy OPS Scope Document B. Vegetation Management Subcommittee (VMS) C. Reliability Coordinator Subcommittee (RCS) D. NERC Resources Subcommittee (RS) E. NAESB Working Group (NWG) F. System Operator Subcommittee (SOS) NERC Personnel Subcommittee update G. Available Transfer Capability Working Group (ATCWG) H. Real-time Modeling Working Group (RMWG) I. Telecommunications Subcommittee (TS) Wes Davis John Johnson Louis Slade Jim Case Eugene Warnecke

Jim Case Jim Case John Troha John Troha John Troha Jim Case John Troha Jim Case Gerald Beckerle Gerald Beckerle Ken Keels Bob Goss Jim Case Mike Hardy Randy Castello Jim Griffith Jim Griffith

1:30 PM

3:00 PM 3:30 PM 3:45 PM 4:00 PM 4:15 PM

Jack Gardner Steve Corbin Larry Akens Pat McGovern Rocky Williamson Wayne Mitchell DuShaune Carter Robert Kingsmore Ben Adams

5:00 PM

Recess for evening

SERC OC Meeting ­ October 14-15, 2010

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SERC Reliability Corporation Operating Committee (OC) MEETING AGENDA October 14, 2010; 1 ­ 5 PM October 15, 2010; 8 AM ­ 12 Noon Biloxi, MS Friday, October 15, 2010

8:00 AM 7. NERC Frequency Response Initiative NERC Generator Governor Survey BA Natural Frequency Response Request FERC Frequency Response Technical Conference - Highlights 8. State of NERC Standards Development and Results Based Standards Bo b Cu m m in g s NERC S ta ff

8:45 AM 9:30 AM 9:45 AM 10:15 AM 10:45 AM 11:15 AM

Da vid Ta ylo r NERC S ta ff P a t Hu n tle y Bo yd Na tio n

9. SERC Standards update/Under-frequency Load Shedding 10. Cyber Security Regulatory Update Break (refreshments) 11. Status of FAC-003-2 12. Round table discussion of significant issues/events Smart Grid topic ­ (real time application of synchro-phasor, update on tools under development by NERC, etc.) 13. Closing comments

J a c k Ga rd n e r J im Ca s e

12:00 PM

J im Ca s e

SERC OC Meeting ­ October 14-15, 2010

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SERC OC LEADERSHIP

October 14-15, 2010 SERC Fall OC Meeting

Biloxi, MS Gerald Beckerle, OC Vice Chair

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SERC OC LEADERSHIP

· New officers for July 1, 2011 ­ June 30, 2013 · Nominations to be taken at spring 2011 meeting

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NOMINATING COMMITTEE

· Chris Bolick (AECI) · George Carruba (EKPC) · Tom Abrams (Santee Cooper) · Jim Griffith (Southern ­ past chair) · Richard Myers (EEI)

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Questions?

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Compliance Program Update

October 14, 2010 Biloxi, MS Ken Keels SERC Director of Compliance

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Overview

· Highlights of 2011 Annual Implementation Plan Focus areas for operating-related standards · Key issues in Compliance for operating-related standards · Lessons-learned · Enhancing your compliance action experience

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2011 CMEP Annual Implementation Plan

· Risk-based and performance-based approach (audit scope may vary by registered entity) · Reduction in core set of Reliability Standards in scope for f S f compliance audits and self-certification · Region discretion on additional audit scope for each registered entity; notification in audit detail letter (90 days) · New standards (MOD-001,004,008,028,029,030; NUC-001) · Spot checks for NUC-001, MOD-028-030 and for RCs on IRO standards · S C Annual Plan due to NERC on November 1; approved and SERC C posted by December 1 · Registered entities expected to be in compliance with ALL applicable FERC-approved standards!

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Risk-Based/Performance-Based Criteria

1. North American-wide standards most violated, all time and rolling twelve-month. 2. 2 Regional Entity specific most violated standards. Entity-specific standards 3. Regional Reliability Standards most violated, as applicable. 4. Registered Entity specific issues, including but not limited to operational issues, operational footprint changes, corporate restructuring, other trends, etc. 5. Random determination (other high risk reliability standards, registered functions trends and concerns, standards rising in prominence and identified through trend analysis) 6. Compliance Culture, which considers the entity's compliance culture and overall strength of compliance. NOTE: SERC will add self-certification for standards for which data submittal is required for reliability services and reliability assessment

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Operating-Related Standards in Base Scope

Reliability Standards (FERC Approved) BAL-003-0.1b CIP-001-1 CIP 001 1 COM-001-1.1 COM-002-2 EOP-001-0 EOP-002-2.1 EOP-003-1 EOP-005-1 EOP-006-1 EOP-008-0 FAC-003-1 FAC 003 1 IRO-001-1.1 IRO-002-1 IRO-003-2 IRO-004-1 IRO-005-2 IRO-006-4.1

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Self-Certification

Audit

Spot Check

Operating-Related Standards in Base Scope

Reliability Standards (FERC Approved) IRO-014-1 IRO-015-1 IRO-016-1 MOD-001-1 (4/1/2011) MOD-004-1 (4/1/2011) MOD-008-1 (4/1/2011) MOD-028-1 (4/1/2011) MOD-029-1 (4/1/2011) MOD-030-2 (4/1/2011) NUC-001-2 (4/1/2010) PER-001-0.1 PER-002-0 PER-003-0 PER-004-1 TOP-001-1 TOP-002-2a TOP-004-2 TOP-006-1 VAR-001-1 VAR-002-1.1b

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Self-Certification

Audit

Spot Check

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Key Issues in Compliance for Operating-Related Standards · VAR-002 ­ voltage schedules and Automatic Voltage Regulator status · New MOD Standards ­ data requirements, verification of methodology · NUC-001 ­ verification of NPIR with "Transmission Entities"

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Lessons-learned

· CIP-001 ­ Define sabotage and include procedures for lateral and downward communication of events and multi-site events · VAR-002 ­ Potentially confusing labeling on automatic voltage regulator controls; AVR alarming disengaged for units returning from shut down · FAC-003 ­ Be aware of changing conditions that can lead to excessive growth; ensure ROW maintenance cycles don't result extra growth res lt in e tra gro th season ( inter/spring one c cle (winter/spring cycle, summer/fall next cycle)

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Enhancing Your Compliance Action Experience

Be prepared Comprehensive self-assessment and self-reporting p p g Provide evidence of compliance and identify any gaps Initiate mitigation activities early; submit mitigation plans early · Complete standard-specific questionnaires (posted on web site) · Provide analysis of actual and potential reliability risk (not only what h l h t happened, b t what could h d but h t ld have h happened) d) · · · ·

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Questions?

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NERC October 14, 2010 Operating Committee Meeting Update

October 14-15, 2010 Biloxi, MS Jim Case SERC OC Chair Case, Entergy

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Meeting Highlights

NERC OC Discussions · Standards · Metrics · Event Analysis · SAFNR ­ Situation Awareness for FERC, NERC, Regions · Frequency Response · Operator Certification

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1

Standards

· NERC proposes to use technical committees in standards development process d l t Guidelines should not become "de-facto standards" Paperwork does not improve reliability Reliability concerns rather than administrative requirements should be operator's primary focus OC, not auditor, should make an informed opinion on standard requirements · OC should consider an effective engagement in standards process ­ Select small number of standards that need to be cleaned up and develop action plan

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Metrics

· 51 ALR proposals evaluated ­ 9 approved in 2009, 8 approved by OC at September 14 15 meeting in Denver 14-15 ORS, IS, and RS to review the 17 metrics to determine which ones provide historical trends that validate performance or indicate trends OC should be concerned about · OC members to provide input on which provide key performance indicators · RMWG conducted a metric and risk assessment webinar on September 21

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Events Analysis/Lessons-learned

· Draft process document will be a living document ­ feedback from members solicited f b li it d · Objective ­ learn from smaller events to prevent larger ones · Over 250 events experienced since June 2007; only 17-18 (mostly) large events have been investigated · Concerns: Is the process going to be transparent for buy-in by the industry? How do we get around the confidentiality requirements and legal roadblocks? How will the NERC EA staff work with the Compliance staff?

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Events Analysis/Lessons-learned (continued)

· A field trial will be conducted to review category 1 and 2 events to get experience of events and determine best way t t t i f t dd t i b t to move forward with process · Field trial to start in mid-October and run three months · Will likely have 1-2 category 1 events per week · Members requested to review specific standards that apply to their event

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Events Analysis/Lessons-learned (continued)

· EAWG will update OC on lessons-learned at December OC meeting; lessons-learned will be standing OC agenda it ti l l d ill b t di d item · Members should contact their regional rep on EAWG for field trial questions

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Situational Awareness ­ FERC, NERC, Regions (SAFNR)

Background · 2009 ( l ) ­ current state of situation awareness not (early) t t t f it ti t sufficient for RROs, NERC, and FERC; SAFNR team formed · 2009 (June) ­ Reliability Coordinators provide initial common displays based on FERC request · 2010 (April) ­ SAFNR Project Team reconstituted; began needs assessment ; NERC identified SA needs, developed RFP based on ES-ISAC goals g · NERC was designated as the responsible entity for ES-ISAC requirements in order to have access to SA information to inform FERC without having to bother operators regarding system conditions

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Situational Awareness ­ FERC, NERC, Regions (SAFNR)

ES-ISAC goals · All Allow NERC and the Regional Entities to monitor conditions d th R i l E titi t it diti on the bulk power system in North America · Allow FERC to monitor conditions on the bulk power system in the United States · Obtain accurate system and impact information in near-real time to identify actual or potential threats to system reliability, with minimal impact to operators directing actions in p p g response to those conditions · Effectively communicate information to potentially affected entities to ensure optimal awareness to conditions

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Situational Awareness ­ FERC, NERC, Regions (SAFNR)

RFP requirements · P id common l k and f l Provide look d feel · Seven-day (minimum) trending · Minimize RC support requirements · Provide situation awareness · Provide for future enhancement/growth

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Situational Awareness ­ FERC, NERC, Regions (SAFNR)

Project schedule · S t b ­D September December 2010 D ft review, i b 2010: Draft, i issue RFP and RFP, d review proposals; recommend selection · June 1, 2011: Phase 1 delivered operational · December 31, 2011: Phase 2 delivered operational

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Frequency Response Initiative

Frequency Response Initiative Team · G th i unit and governor data to assess why frequency Gathering it d d t t h f response is declining · Published set of mutually-understood terminology and requested comments from industry Concerns expressed · Why isn't technical research on a standard done by technical committees and brought to the OC before a SAR is developed? · Should the OC take charge of the FRI to ensure appropriate research and efforts are conducted to develop a resolution to this issue?

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Frequency Response Initiative

OC Chair (Sam Holeman) ­ the OC has been, is and will continue to be involved in the review analysis and review, management of frequency response FERC held a four-hour technical conference on frequency response in Washington, DC on September 23, 2010

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Operator Certification

The NERC BOT is concerned that passing rate for operator certification h d li d t 69% and requested the OC to tifi ti has declined to d t d th t determine if this was a cause for concern · Members felt the pass rate was acceptable for initial certification of new operators ­ tests are also more rigorous

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Questions?

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Reliability Metrics Task Force

October 14-15, 2010 Biloxi, MS Randy Castello y Chair of SERC OC Task Force on Metrics

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Topics

· · · · Reminder: why metrics 2009 Metrics 2010 Metrics RMWG future activities

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Why Metrics

Rules of Procedure: Section 809 · NERC shall identify and track key reliability indicators as a means of benchmarking reliability performance and measuring reliability improvements · Include assessing available metrics, developing guidelines for acceptable metrics · Maintaining a performance metrics "Reliability Indicators" on the NERC Web site, and · D Developing appropriate reliability performance b l i i li bili f benchmarks h k

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2009 Metrics

ALR1-3 ALR1-4 ALR2-4 ALR2-5 ALR3-5 ALR4-1 ALR4 1 ALR6-1 ALR6-2 ALR6-3

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Planning Reserve Margin BPS Transmission Related Events Resulting in Loss of Load Average Percent Non-Recovery of Disturbance Control Standard (DCS) Events Disturbance Control Events Greater than Most Severe Single Contingency (MSSC) Operating Limit Excursion (OL Excursion) Percent of Automatic Transmission Outages caused by g y Failed Protection System Equipment Transmission Constraint Mitigation Energy Emergency Alert 3 (EEA3) Energy Emergency Alert 2 (EEA2)

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2010 Metrics

ALR1-5 ALR1-12 ALR2-3 ALR6-11 ALR6-12 ALR6-13 ALR6-14 ALR6-15 System Voltage Performance Interconnection Frequency Response UFLS Activation Automatic AC Transmission Outages Initiated by Failed Protection System Equipment Automatic AC Transmission Outages Initiated by Human Error Automatic AC Transmission Outages Initiated by Failed AC Substation Equipment Automatic AC Circuit Outages Initiated by Failed AC Circuit Equipment Element Availability Percentage

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ALR1-5

· Sponsor Group: RMWG · Short Title: Transmission System Voltage Profile · Metric Description: measure the transmission system voltage performance over time. · Purpose: measure the transmission system voltage performance (either absolute or per unit of a nominal value) over time which provides an indication of the reactive capability applied to the transmission system. Record the amount of time that system voltage is outside a predetermined band around nominal.

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3

ALR1-12

· Sponsor Group: Resources Subcommittee · Short Title: Interconnection Frequency Response · Metric Description: the metric is to track and monitor Interconnection Frequency Response. · Purpose: there is evidence of continuing decline in Frequency Response in the three Interconnections over the past 10 years, but no confirmed reason for the apparent decline. The metric data trends and analysis will assist in identifying root causes of decline decline.

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ALR2-3

· Sponsor Group: RMWG · Short Title: UFLS Activation · Metric Description: number of activation of UFLS by each region and total MW of load interruption by each region and NERC wide. · Purpose: the purpose of the underfrequency load shedding (UFLS) is mitigation for when the system does not perform in an acceptable manner after a credible contingency.

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ALR6-11

· Sponsor Group: NERC · Short Title: AC Transmission Outages - Failed Protection System q p Equipment · Metric Description: normalized count of 200 kV and above AC Transmission Element outages that were initiated by Failed Protection System Equipment. This metric will use the TADS data and definition of Failed Protection System Equipment. · This metric includes protection system equipment-related problems such as equipment failure, relay setting drifting, and internal relay logic or algorithm errors, and excludes misoperation causes such as miscoordinated settings, incorrect setting calculations, and errors in applying settings to the relay which are classified in TADS under human errors. · Purpose: the purpose of this metric is to gauge Failed Protection System Equipment as one of many factors in the performance of AC transmission system Automatic Outages.

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ALR6-12

· Sponsor Group: NERC · Short Title: AC Transmission Outages - Human Error · Metric Description: normalized count of 200 kV and above AC Transmission Element outages (i.e., TADS momentary and sustained Automatic Outages) that were initiated by human error. This metric will use the TADS definition of human error. Any human failure or interpretation of standard industry practices and guidelines that cause an outage will be reported in this category." Transmission Elements in this metric includes AC Circuits and Transformers. This metric includes protection system misoperations due to human error such as miscoordinated settings, incorrect setting calculations and errors in applying settings to the relay in calculations, relay, addition to the other human errors identified in the TADS Data Reporting Instruction Manual for the Automatic Outage Cause Code, Human Error. · Purpose: the purpose of this metric is to gauge human error as one of many factors in the performance of AC transmission system Automatic Outages.

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5

ALR6-13

· Sponsor Group: NERC · Short Title: AC Transmission Outages ­ Failed AC Substation Equipment · Metric Description: normalized count (on a per circuit basis) of 200 kV and above AC Transmission Element outages that were initiated by failed AC substation equipment. This metric will use the TADS definition of "Failed AC Substation Equipment". The TADS definition of "AC Substation" states, "An AC Substation includes the circuit breakers and disconnect switches which define the boundaries of an AC Circuit, as well as other facilities such as surge arrestors, buses, transformers, wave traps, motorized devices, grounding switches, and shunt capacitors and reactors. reactors Series compensation (capacitors and reactors) is part of the AC Substation if it is not part of the AC Circuit. · Purpose: the purpose of this metric is to gauge failed substation equipment as one of many factors in the performance of transmission system Automatic Outages.

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ALR6-14

· Sponsor Group: NERC · Short Title: AC Transmission Outages ­ Failed AC Circuit Equipment · Metric Description: normalized count (on a per 100 circuit-mile basis) of circuit mile 200 kV and above AC Transmission Element outages (i.e., TADS momentary and sustained Automatic Outages) that were initiated by failed AC circuit equipment. This metric will use the TADS definition of "Failed AC Circuit Equipment", which states "Automatic Outages related to the failure of AC Circuit equipment, i.e., overhead or underground equipment `outside the substation fence.' Refer to the TADS definition of "AC Circuit", which states "A set of AC overhead or underground threephase conductors that are bound by AC Substations Radial circuits are Substations. AC Circuits." Transmission Elements in this metric include AC Circuits only. · Purpose: the purpose of this metric is to gauge failed AC circuit equipment as one of many factors in the performance of transmission system Automatic Outages.

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ALR 6-15

· Sponsor Group: SERC Reliability Corporation · Short Title: Element Availability Percentage (APC) · Metric Description: overall percent of time the aggregate of transmission system facilities (i.e., AC lines and transformers operated at 200 kV and above) are available for service. This includes outages caused by both automatic and non-automatic events. Momentary outages are not included in this calculation. · Purpose: to determine the percent of time that the transmission system operated at 200 kV and above is available when outages due to automatic and non-automatic events are considered.

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ALR 1-5

ALR 1-5 T r i a l Ru n - BU S1 50 0 k v (+4% a n d a bo v e, -1% a n d bel o w , i n 20 0 9)

100 80 60 40 20 0 20 40 60 80 100 81 28 1 7 19 65 3 3 22

Above Count Below Count

Mi inutes Out of Range

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Month

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ALR 6-11

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RMWG Future Activities

· Constant review of existing metrics to assure they are useful (17 current metrics) · Solicit new ideas from the industry · 2010 Comments on Proposed Metrics · New metric ideas can and do come from RMWG, NERC staff, Standing Committees, subgroups, etc.

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Questions?

17

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NERC Events Analysis Working Group

October 14-15, 2010 Biloxi, MS

Jim Griffith Southern Company

1

NERC EAWG History

· Originally was the NERC "Events Analysis Coordination Group Group" until January 2010 One member from each Regional Entity NERC Event Analysis staff

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1

NERC EAWG History

· January, 2010 the NERC OC and PC Executive Committee and NERC added members and renamed the group - Events Analysis Working Group EACG members plus OC and PC representatives First meeting March 15, 2010 · Started development of goals to be accomplished and a scope for the group

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NERC EAWG History

· NERC OC members added: Ben Deutsch ­ Midwest ISO Jim Griffith ­ Southern Company Paul Johnson - AEP

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2

NERC EAWG History

· Develop a plan to achieve NERC BOT Goal 1a "Implement procedures for the triage, investigation, root cause analysis, and the transparent reporting of system events for the purpose of improving reliability performance and tracking recommendations (lessons-learned); team with Regional Entities and engage registered entities in rigorous self-evaluation of system events and risk mitigation."

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NERC EAWG History

· Goal established that by September 30, 2010 "Reach consensus among NERC management, Regional Reach management Entity Executives, Events Analysis Working Group, and NERC Planning and Operating Committees on a set of procedures for analyzing and investigating events on the bulk power system that are rigorous, thorough, and timely, and which satisfy the needs of applicable governmental authorities"

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NERC EAWG History

Fifteen key areas were addressed for input - some of which were: · Who is the audience for these processes and other content questions · Input on consistency of processes · How to provide incentive for rigorous, thorough and timely self-assessment and self-reporting · Event categorization and investigation assignment

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NERC EAWG History

Fifteen key areas were addressed for input; some of which were: · Roles, responsibilities, rights of all and avoidance of duplication · Measuring success · Possible obstacles that could hinder full realization of these objectives ­ compliance, confidentiality, etc.

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NERC EAWG History

Initial "Straw Dogs" · Process steps document To provide clarity to registered entities, regional entities, NERC staff, and governmental authorities regarding process expectations of each · Reporting requirements definitions Top provide clarity to registered entities, regional entities, NERC staff and governmental authorities regarding what events to report · Training Documents Root Cause techniques, etc.

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NERC EAWG History

Timelines: · By week of July 12 ­ Final agreement by team on documents, content, and writing assignments · By week of August 3 ­ Review of initial draft documents · By week of August 23 ­ Finalize documents for NERC OC and PC meetings · September 14-15 - PC and OC give final input to draft documents · Week of September 27 ­ Final consensus of all participants and posting of documents establish Webex etc documents, Webex, etc.

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NERC EAWG History

Purpose of the EAWG approved by the NERC OC and PC. What the EAWG is: · The EAWG is a cross-functional group of industry experts that will develop a cohesive and coordinated events analysis process across North America in coordination with industry participants, NERC and Regional Entity staffs · Maintain a consistent set of processes and procedures for use by the industry to report, categorize, analyze and disseminate lessons learned from BES events

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NERC EAWG History Purpose of the EAWG approved by the NERC OC and PC What the EAWG is NOT: PC.

Involved in COMPLIANCE

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NERC EAWG History To fulfill the stated objective, the EAWG will:

· Provide coordination between industry participants, NERC staff, and the RE staffs to facilitate consistency in the EA process · Encourage collaboration among NERC, RE staff and the operating entities to promote consistency of EA procedures · Promote the identification and dissemination of the "lessons-learned" from events analysis throughout the industry

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NERC EAWG History Governance: The EAWG is a joint effort of the NERC PC and OC and will report directly to both committees. The PC and OC will jointly consider the deliverables, recommendations and final work products of the g g EAWG for endorsement along with reviewing the scope periodically.

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Questions?

15

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SERC Three (3) Year Work Plan

October 14-15, 2010 Biloxi, Ms.

Jim Griffith Southern Company

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OPERATING COMMITTEE GOALS THREE YEAR WORK PLAN

· Presentation Purpose ­ provide an update on the development of a th d l t f three-year work plan f th SERC k l for the Operating Committee · Three-year Work Plan Development Team Members Gerry Beckerle Bob Dalrymple Jim Griffith Melinda Montgomery

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OPERATING COMMITTEE GOALS THREE YEAR WORK PLAN

Reviewed: · Initial recommendations from SERC Spring 2010 Meeting and summer phone conference input · NERC 2010 performance goals and objectives · NERC OC 2010 three-year work plan (may change again)

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OPERATING COMMITTEE GOALS THREE YEAR WORK PLAN

Goal ­ improve reliability throughout NERC Actions: Actions · Participate in and support the development of an industry program to systematically address risk to the reliability of the bulk power system · Provide opportunities for members to share lessons learned from system events to improve the reliability of the bulk power system · Provide opportunities to improve the technical knowledge of SERC OC members

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2

OPERATING COMMITTEE GOALS THREE YEAR WORK PLAN

Goal ­ Improve Adherence to NERC Standards by participation in the Standard Development P i th St d d D l t Process Actions: · Improve consistency, transparency and efficiency of the compliance process · Develop performance based standards and improve timelines of the standards process · Improve delivery of results for physical and cyber security initiatives

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OPERATING COMMITTEE GOALS THREE YEAR WORK PLAN

Goal ­ Improve understanding of the nature of the BPS by outside parties t id ti Actions: · Improve government and stakeholder relations

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OPERATING COMMITTEE GOALS THREE YEAR WORK PLAN

Goal ­ improve the effectiveness of cost controls and stewardship funding ste ardship of f nding Actions: · Implement cost control initiatives where possible

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OPERATING COMMITTEE GOALS THREE YEAR WORK PLAN

Activities required to support the Plan by the OC, OC q pp y , subgroups and SERC staff such as: · Periodically review the OC Subcommittee and Working Groups Scope Documents to ensure alignment · Maintain coordination among SERC members to full-fill the specific responsibilities assigned to each subgroup · Foster a spirit of open communications

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OPERATING COMMITTEE GOALS THREE YEAR WORK PLAN Activities required to support the Plan by the OC, OC subgroups and SERC staff such as:

· Provide support to the standard development process · Monitor the notice of posting for comment and inform the OC, schedule Webex conference calls, facilitate the development of comments · Monitor NERC OC activities and inform · D Develop b d t consistent with philosophy l budgets i t t ith hil h

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Questions?

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OC MEETING

2010 Overview Situation Awareness

October 14-15, 2010 Biloxi, MS Wes Davis SERC Manager, Situation Awareness

OC MEETING

2010 Highlights

· Over 100 events triaged SERC bypassed in 2 of 100 events · Abbreviated reports developed ­ 2 · Final disturbance reports developed ­ 1 (in progress) · Continue to work with SERC membership on communicating events of interest .

1

OC MEETING

2010 Highlights

· Serve as liaison between FERC, NERC, and membership on situation awareness activities SERC has been bypassed in 2 of 100 events · Continued strong relationships with RCs and BAs on situation awareness activities · Implemented SAFNR tools into SERC day-to-day activities · SAFNR Phase 2 ­ in progress

OC MEETING

Events through October 1, 2010

100 100 90 80 70 60

Number of Events

50 40 30 20 10 0

Total Events 2010 Operations Resource Adequacy EMS/SCADA Weather FTL Sabotage Other

35

34

7

6

6

10 2

2

OC MEETING

Cumulative Events ­ 2009 through October 2010

200 180 160 140 120 100 80 60 40 20 0

Total Events 1/09 - 2010 EMS/SCADA Sabotage Operations Weather Other Resource Adequacy FTL

192

73 42 13 34 15 12 3

OC MEETING

Questions?

3

Events Analysis Update

October 14-15, 2010 Biloxi, MS John Johnson Manager, Events Analysis

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Agenda

· · · · · · Goal of the new ERO EA process Philosophy and key ingredients Trial test period Events analysis process Questions Appendices

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1

Goal

· Promoting reliability · Developing a culture of reliability excellence Bottom up approach Ongoing self-critical review and analysis · Collaboration ­ working together · Being a learning organization

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Philosophy and Key Ingredients

· Identify what transpired ­ sequence of events · Understand the causes of events · Identify and ensure timely implementation of corrective actions · Develop and share recommendations and valuable lessons learned to the industry · Enhance operational performance and avoid repeat events

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2

Trial Test Period

· Starts October 25, 2010 · Events occurring on/after that day should be analyzed using the new EA process · Register your comments and concerns during this period · Trial test period might end late 2010

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ERO Event Analysis Process

· Registered entities are required to report · Need to become more quickly aware of events and disturbances · In all cases, the registered entity should be expected to provide at least a preliminary event report within five (5) business days (many are required within 24 hours) of the event

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3

Process Steps

· Complete event report template (Appendix A) · Determine event categories and levels of analysis (Appendix B) · Process event evaluation checklist to determine scope of work needed (Appendix C) · Prepare lessons-learned sample (Appendix D) · For a summary of roles, responsibilities, and expectations for event reporting and analysis (see Appendix E) · Registered entity process checklist (Appendix F) · Compliance assessment template (Appendix G)

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Questions?

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4

Appendices

· Appendix A -- Event Report Template · Appendix B -- Event Categories and Levels of Analysis · Appendix C -- Event Evaluation Checklist · Appendix D -- Lessons Learned Template

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Appendices (continued)

· Appendix E -- Summary of Roles, Responsibilities, and Expectations for Event Reporting and Analysis · Appendix F -- Registered Entity Process Checklist · Appendix G -- Compliance Assessment Template

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SERC OC Triage Team

October 14-15, 2010 Biloxi, MS Louis Slade SERC Triage Team Chair

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Team Members

· · · · · Louis Slade Larry Akens Hugh Francis Rick Wischer John Johnson

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Purpose

To apprise SERC OC members of FERC directives, orders, announcements and/or technical conferences that might be of importance or are expected to have a significant impact on SERC members

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OC Feedback?

· Information Too much Too little · Format · Timeliness · Other

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2

Questions?

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3

OPS Update to OC

October 14-15, 2010 Biloxi, MS Eugene Warnecke g OPS Chair

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Request for OC Approval

RRO Implementation Procedure EOP-004-1 · R1 Each Regional Reliability Organization shall establish R1. and maintain a regional reporting procedure to facilitate preparation of preliminary and final disturbance reports · Provides a summary for Operators to report disturbance events

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1

Request For OC Approval

SERC Contingency Reserve Policy · Updates to Midwest ISO MB Hydro Reserve Sharing Group ISO-MB and TVA-EKPC-E.ON.U.S. (TEE) Reserve Sharing Group

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Request For OC Approval

OPS Scope document · Updated to represent current responsibilities activities and responsibilities, activities, membership

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2

Questions?

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3

Vegetation Management Subcommittee (VMS) Update

October 14, 2010 Biloxi, MS Gardner Presentation

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VMS Update

· SERC VMS reliability alert (August 31st) Notice to f N ti t refocus on VM efforts d i hi h risk period ff t during high i k i d · NERC Alert (Industry Advisory for VM on September 15th) Response to increase in outage reports during 3rd Quarter · Change in VMS chair Jeff Hackman (Ameren) will replace Jack Gardner (PEC) as chair of VMS in November · VMS continues to review and comment on FAC-003-2 draft FAC 003 2 postings

2

1

Questions?

For additional information www.serc1.org

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2

Reliability Coordinator Subcommittee (RCS) Report

October 14-15, 2010 Biloxi, MS Steve Corbin RCS Chair

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Reliability Coordinator Subcommittee (RCS)

· Change in chair of the RCS from Steve Corbin to Joel Wise, recommended by the RCS and appointed by Jim Case, OC Chair · Joel Wise is presently vice-chair of the RCS

2

1

Questions?

3

2

October 13, 2010

Mr. Steve Corbin Southern Company Services 600 North 18th Street P.O. Box 2641 Birmingham, AL 35203-2206 Dear Mr. Corbin: On behalf of SERC and its members, we want to express our gratitude for the leadership you have provided during your tenure as the Southeastern Reliability Coordinator since implementation of the SERC Subregional Security Plans in 1997 and your service as chairman of the SERC Reliability Coordinator Subcommittee (RCS) on more than one occasion since its formation in 2004. Your knowledge of power system operations and your realistic approach to problem solving through coordination and cooperation with neighboring RCs, BAs, and TOPs have been instrumental in improving and maintaining the reliability of the electric system in the SERC Region. On behalf of SERC Reliability Corporation, thank you for your guidance, encouragement, and leadership. Sincerely,

R. Scott Henry SERC President and CEO

WDavis:dms:10/11/10 Jim Case Jim Griffith Steve Williamson Master File Desk Copy

Resources Subcommittee Report

October 14-15, 2010 Biloxi, MS Larry Akens Presenter

Standard Development Initiatives Sponsored by RS

· · · · Balance Area Control SDT (BACSDT) Frequency Response SDT (FRSDT) Reliability Based Control SDT (RBCSDT) BACSDT and RBCSDT have been combined Balance Area Reliability Control SDT (BARCSDT) Co-chaired by Doug Hils and Larry Akens

1

Raymond Vice

· During the July 2010 Resources Subcommittee meeting Raymond Vice was recognized for his contributions to the NERC Resources Subcommittee · Thanks Raymond

BARCSDT

· SDT developing revisions to four standards

BAL-002 BAL 002 BAL-004 BAL-005 BAL-006 Disturbance Control Performance Time Error Correction Automatic Generation Control Inadvertent Interchange

· SAR was sponsored by the NERC Resources Subcommittee

Address issues raised by FERC Order 693 yp p Collaboratively participate with NAESB where NAESB WEQ Standards exist (BAL-004 and BAL-006) Incorporate necessary content, structure, and language to comply with NERC Standards Development Plan

2

BAL-002, Disturbance Control

· Incorporate FERC Order 693 requirements

Include requirements that explicitly provides Demand Side Management (DSM) may be used for contingency reserves

· SDT has discussed with FERC "continent-wide" reserve policy

FERC has recommended that SDT develop reserve definitions Consider a Reserve Standard that would define requirements for contingency, regulating, and frequency reserves.

· Recognize loss of transmission as well as generation as a possible event that may require contingency reserves · Define significant frequency deviation as a threshold for a reportable event resulting from loss of supply, loss of load, and significant scheduling problems · BARCSDT is developing draft standard with schedule to post for comments early 2011.

Reserve Policies

· Initial attempt will be to modify existing standards to incorporate reserve requirements i t i t BAL-001 Regulating Reserves BAL-002 Contingency Reserves BAL-003 Frequency Responsive Reserves · In lieu of standalone reserve standard which would require modification to the SAR

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BAL-004 ­ Time Error Correction

· FERC NOPR proposed to remand BAL-004-1 · Discussions between NERC and FERC staff discussed possible elimination of BAL-004 · FERC granted stay to allow for field test · Field test proposal has been prepared along with white paper for presentation to NERC SC pp proposed field test, it will be p passed to · If NERC SC approves p p the NERC OC for implementation

BAL-004 ­ Time Error Correction Proposed Field Test

· Based on data collected for the Eastern Interconnection, more th 40% of FTL l than f low (59 5 H t ) over a one minute (59.5 Hertz) i t average occur during fast TEC · Proposed field trial will stop TEC for all Interconnections · Require waiver for BAL-004, R2 as well as work with NAESB for WEQBPS-004-000 · Determine business impacts if time error is not corrected · Proposed field trial will start in 2011 and run for one year · Resources Subcommittee will oversee, collect data, and evaluate results

4

BAL-005 ­ Automatic Generation Control BAL-006 Inadvertent Interchange

· Some preliminary work has been done · Draft for revisions to BAL-005 and BAL-006 are expected to be posted for comments early 2011.

Frequency Response SDT

· Frequency Response SDT is working to incorporate clarification into the BAL 003 standard regarding frequency BAL-003 response versus the bias term in the ACE equation · Team efforts include defining frequency event parameters, collecting BA data, evaluating data, and drafting standards as necessary · Targeted frequency response will be identified for each BA · Bill Herbsleb, PJM, is chairing this SDT , , g

5

Frequency Response Initiative

· NERC team headed by Bob Cummings · Frequency response (or lack of) is one of 3 NERC major reliability concerns · NERC has through the NERC Alerts requested data Frequency Response Generator governor data · Bob Cummings will speak during our meeting and will provide you details and status of his team's initiatives

Interesting Charts

· Decline of Frequency Response in Eastern Interconnection · Ideal frequency response showing ACB curve · Typical Eastern Interconnection frequency response

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Eastern Interconnection Frequency Response 2000 ­ 2008

Eastern Interconnection Beta

3500 3400 3300

MW/0.1Hz

3200 3100 3000 2900 2800 2700 2600 2500 2000 2001 2002 2003 Mean 2004 Median 2005 2006

2007-2008 Response = -2550 2007 2008 R 2550 MW/0.1Hz

*

Classic Frequency Excursion Recovery

Frequency (Hz)

60 050 60.050 60.025 60.000 59.975 59.950 59.925 59.900 59.875 59.850 59.825 59.800 59.775 59.750

-30 0 30 60 90 120 150 180 210 240 270 300 330 360 390 420

Excursion Recovery

Recovery Completed, TV

A = 60.000

B = 59.874 C = 59.812

Time (Seconds)

7

Typical Eastern Interconnection Frequency Excursion

60.02 60.01 60 01 60 59.99 59.98 59.97 59.96 59.95 59.94 0 6 12 18 24

No "Point C" to "Point B" Recovery

Response "Withdrawal"

Seconds

30

36

42

48

54

60

Balance Area ACE Limit Field Trials

· BAAL field trials continue without any reliability concerns being identified NERC SC may move the SDT towards posting in the Eastern Interconnection for ballot Current SDT direction is to modify BAL-001 to include the BAAL metrics Much work has been done to develop ACE Transmission Limit for those quadrants in BAAL that are unbounded q

­ Preliminary indications are the NERC SC may not support ­ Encourage to move forward with the original purpose statement ­ More information after NERC SC meeting

8

Questions

Questions?

9

Date: To: From:

October 7, 2010 SERC Operating Committee SERC ­ OC NAESB Working Group Chairman/ Patrick McGovern

Subject: NWG Report

Items Out for Formal or Informal Comment:

WEQ 2010 AP Item 1d Monitor and develop NAESB business practices as needed to complement NERC reliability standards for FAC-012 and FAC-013. Informal Comments request on second phase of proposed measurement and verification business practice standards for Wholesale Electric Market Demand Response Programs http://www.naesb.org/pdf4/dsmee_group3_093010reqcom_a2.doc Request for Comments Due October 25, 2010 Request for Comments Due October 29, 2010

WEQ 2008 AP Item 5a

Selected Final NAESB Wholesale Electric Quadrant (WEQ) Actions: WEQ Final Actions - To be applied to Version 002.2 2011 ·

1

est. to be published 2nd Quarter

Gas/Electric Coordination (July 15, 2010) WEQ 2009 Annual Plan ("AP") Items 5.a.2 and 5.i. The purpose of the Gas / Electric Coordination Standards Business Practice (WEQ011) is to improve the coordination between the gas and electric industries in daily operational communications between Transportation Service Providers and gas-fired power plants. The modifications made to this Business Practice included: 1) deleting the acronym PPO; and 2) deleting the definition of terms Power Plant Operator and Power Plant Operator Facility.

·

Smart Grid (August 20, 2010) On September 30, 2009 the National Institute of Standards and Technology ("NITS") assigned NAESB the responsibility to develop Requirements and Use Cases pertinent to Priority Action Plan items 3, 4 and 9. A complete description is available on the NIST Web site: http://collaborate.nist.gov/twiki-sggrid/bin/view/SmartGrid/WebHome WEQ 2010 AP Item 6(a) The WEQ 2010 AP Item 6(a) pertains to PAP 03, "Develop Common Specification for Price and Product Definition", to capture business and data requirements related to the

1

All NAESB Standards are protected under United States Copyright laws. Non-Members may purchase the NAESB Business Practice Standards (see http://www.naesb.org/pdf/ordrform.pdf).

1

definition of a common model for attributes of an electricity product offered at wholesale and/or retail level. Such attributes include the pricing information of the product being offered to the end consumers of electricity. The NAESB Smart Grid Task Force (SGTF) developed this Business Practice that that identifies the attributes used as a basis for messaging protocols throughout the electrical energy system from producer through to a variety of energy consumers and the future intelligent devices employed by these consumers. These attributes are not meant to be a message protocol in and of themselves and further analysis and design work will be completed as part of several initiatives, such as ZigBee smart energy, OpenHAN, and OASIS eMIX. These requirements should also be used as an input to the CIM maintained by UCAIug. WEQ 2010 AP Item 6(b) The WEQ 2010 AP Item 6(b) pertains to PAP 04, "Develop Common Schedule Communication Mechanism for Energy Transactions", for the coordination of supply and demand information and schedules related to the expected future increase of distributed energy resources, including both distributed energy generation and demand response. The coordination involves more than electromechanical coordination; it also involves enterprise activities, home operations and family schedules, and market operations. WEQ 2010 AP Item 6(c) The WEQ 2010 AP Item 6(c) pertains to PAP 09, "Standard DR and DER Signals", to develop a common semantic model for standard DR signals. The NIST effort aims to ensure that DR & DER signal standards support load control, supply control, and environmental signals. The NAESB Business Practice address standardizing the information exchanged during interactions between the System Operator and various Market Participants for the administration and deployment of demand response resources in organized wholesale electric markets. Additional Business Practice Standards are under development on other aspects of the PAP 09 objectives. Selected NAESB Standards Under Development Supporting Reliability Standards: · Parallel Flow Visualization Transmission Loading Relief (PFV ­ TLR) NWG encourages operating personnel to participate in upcoming NAESB meetings on the implementation of the proposed solutions. http://www.naesb.org/weq/weq_bps.asp Interim solution for Parallel Flow Visualization is completed. The interim solution is needed to support November 1, 2010 NERC implementation of Interchange Distribution Calculator ("IDC") Change Order 283 into the IDC Staging Environment. The interim solution establishes transmission service priorities for intra-BA delivery of generation to load for those entities that do not have a regulatory-approved market-based congestion management process using flowgate allocations to assign firm and non-firm market flow priorities. The interim solution will not be used for production TLR curtailments. The subcommittee anticipates a permanent solution will be developed by November 1, 2011. Background:

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The Parallel Flow Visualization Transmission Loading Relief ("PFV ­ TLR") project addresses three issues: (1) the use of static data in Native and Network Load calculation, (2) Reliability Coordinators in Eastern Interconnection lack visualization as to the source and magnitude of parallel flows when they experience congestion, and (3) priorities of generation to load impacts during firm curtailment. With NERC IDC Change Order 283 addressing the first issue, the NAESB effort has been primarily focused on the identification of the generation-to-load priorities to be collected for use by the IDC. The resulting PFV-TLR process will enter into a parallel testing phase in November 2010 ­ it will not be used in providing calculated results to the production IDC. The test IDC will, however, provide a perspective on what curtailment decisions would have been made had the new process been in production. During this 12-18 month test period, the results will be compared to the existing production IDC calculations, with the hope that any lessons learned will be ultimately incorporated into an improved production IDC. The WEQ Business Practices subcommittee has been actively developing draft standards to support this effort through the identification of firm and non-firm flows within a Balancing Authority. In April, the subcommittee formed three task forces assigned to explore alternatives for reporting generation-to-load flows to the IDC and report back to the full subcommittee with their findings. The members who volunteered to contribute their expertise to the flowgate allocation, generator prioritization, and tagging task forces expended considerable energy and time in this effort, providing detailed reports in late June. In consideration of the certainty of NERC's November 2010 parallel test launch date, the subcommittee decided to develop supporting NAESB standards in two stages, consisting of an interim solution and a permanent solution. The interim solution recommendation, which provides NERC the functionality needed to initiate its test, was circulated for formal comments prior to NAESB WEQ Executive Committee (EC) consideration. The WEQ EC is expected to take action on the interim solution when it meets on October 26, 2010. In recognition of the differing structural approaches currently being used across the Eastern Interconnection, this set of standards does not prescribe a particular methodology for identifying and reporting firm and non-firm flows to the IDC. The second phase of this PFV-TLR project, which is currently under way, is intended to standardize how firm and non-firm flows are identified and reported to the IDC. · Time Error and Inadvertent (BAL-004 and BAL-006) Coordination with NERC Status: Monitor. Coordination with NERC - Balancing Authority Reliability Based Controls Standards Drafting Team ("BARCSDT") created in July 2010. DCS and AGC (BAL-002 and BAL-005) Coordination with NERC Status: Monitor. (Coordination with NERC - BARCSDT). Coordinate Interchange Business Practice Standard supporting EOP-002-2 R4 and R6 Review WEQ-004 Coordinate Interchange Business Practice Standard in light of NERC Project 2008-12, Coordinate Interchange Standards Revisions. Status: Not Started. Estimated Completion date 2011. (Dependent on NERC activity).

· ·

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·

Develop Business Practice Standards as companion to the NERC standards for ATC related efforts (MOD-001) Status: Underway. The processing of transmission service requests, which use TTC/ATC/AFC, in coordination with NERC changes to MOD-001 where the allocation of flowgate capability based on historical Network Native Load impacts the evaluation of transmission service requests, requiring the posting of those allocation values in conjunction with queries of service offerings on OASIS. 2010 WEQ Annual Plan Item 2(b) Monitor and develop NAESB business practices as needed to complement NERC reliability standards for FAC-012 and FAC-013. Status: Started ­ The subcommittee began reviewing FERC Orders 693, 729, and 890 and NERC SARs to understand how FAC-012 and FAC-013 were linked to NAESB as possibly requiring coordination. The NAESB working group has determined that complementary standards need not be developed and recommends that this item be closed indicating that no additional Business Practice Standards are required. Comments due October 25, 2010.

·

Other Noteworthy NAESB Activities: · Selected Upcoming Events NAESB Members and Non-Members are encouraged to participate in: o WEQ 2011 Annual Plan conference call / webcast October 20, 2010. http://www.naesb.org/annual_plan.asp o WEQ Executive Committee meeting October 26, 2010.(in person, conference call, and webcast) http://www.naesb.org/weq/weq_ec.asp Transition the TSIN Registry (TSIN) from NERC to NAESB. NAESB has entered into an agreement with OATI for the Electric Industry Registry (formerly known with NERC as TSIN). Industry participants will be required to reregister. A NAESB press release is forthcoming in the near future. Demand-Side Management and Energy Efficiency On April 15, 2010, FERC issued its final rule adopting the WEQ Phase 1 Demand Response (DR) Measurement and Verification (M&V) standards. In the final rule, the Commission noted that NAESB was best suited to develop the Phase 2 standards, noting that "additional substantive standards would appear beneficial in creating transparent and consistent measurement and verification of demand response products and services in wholesale electric markets. The measurement and verification standards needed to accomplish this goal should be a focus of NAESB's Phase II M&V Standards development efforts." The Commission also set a one-year deadline to either complete the Phase 2 standards, or report the progress made in the Phase 2 efforts. The Wholesale DR work group created three task forces (glossary, model business practices and performance evaluation methods) to accomplish Phase 2 work. The glossary task force has reviewed and synchronized the wholesale and retail DR glossary terms and presented their work product to the Wholesale DR work group. The model business practices and performance evaluation methods task force work is ongoing, with a targeted completion date of early September 2010.

·

·

4

The EE efforts at NAESB develop standards to measure and verify reductions in energy and demand from energy efficiency in both wholesale and retail markets, including standards to measure and verify energy reductions that are made to comply with a either a Renewable Portfolio Standard that included energy efficiency, or a stand-alone Energy Efficiency Portfolio Standard. The Retail EE group has been considering phasing the standards development in a manner similar to the DR work. The Retail EE work group has finished its scope document and has begun to draft their recommendation DSM-EE subcommittee, while the Wholesale EE work group is also currently drafting their recommendation, based on EE efforts underway at ISO-NE and PJM. · Smart Grid Activities: The NAESB subcommittee has divided the Smart Grid activities into two phases: Phase 1 develops use cases and initial data requirement standards (see above WEQ Final Actions), and Phase 2 creates expanded data requirement standards. The subcommittee is currently working on Phase 2, with a target for a 3Q 2010 completion date. In late June, the WEQ formed a new subcommittee to address PAP 10 (Energy Usage Information Model). This Smart Grid Standards PAP 10 Subcommittee has been holding weekly meetings and has produced and posted a draft work product for informal industry comment. The draft recommendation treated the retail and wholesale markets identically. The PAP 10 effort is currently on target to submit a NAESB-ratified Model to the SGIP by early December 2010. The work products developed through NAESB's process by both the Smart Grid Standards Development subcommittee and PAP 10 subcommittee will be submitted to both federal and state regulators. In a separate but related development activity, the Open ADE Task Force, operating within the UCA International User's Group, submitted a standards request to NAESB for the standardization of the exchange of energy usage information that is intended to facilitate the transfer of information between designated parties. This request will build upon the OpenADE 1.0 Requirements document. · OASIS Subcommittee Activity on Network Integration Transmission Service ("NITS"): The OASIS systems that manage the electronic scheduling of wholesale electricity were initially designed to support point-to-point transmission services. For several years, the WEQ OASIS subcommittee has been working diligently to establish standards permitting OASIS to accommodate network integration transmission service, or NITS, as mandated by FERC in Order No. 890. Although differing operational structures throughout the country have made the standards development work quite complex, the subcommittee has worked tirelessly to harmonize these realities into a single set of standards. Once this project is complete, it is hoped that the marketplace will benefit greatly from increased uniformity and transparency for transmission services. A substantial number of standards will be integrated into WEQ-001, WEQ-002, WEQ003, and WEQ-013 to support NITS on OASIS. The subcommittee is currently evaluating the informal comments it received from the industry in mid-July 2010 for incorporation into the final proposed business practice standards. It is hoped that final proposed standards will be approved by the subcommittee in late December 2010. In

5

addition, a technical team is currently nearing completion of draft supporting technical standards to permit the seamless implementation of the new standards. The final draft standards are planned to be posted for a formal 30-day industry comment period by early January 2011. · Wholesale Electric Service Across Multiple Transmission Systems: Currently, a transmission customer hoping to move energy across multiple transmission provider systems could be left with a financial obligation to pay for committed capacity on one system without a guarantee that the energy will be able to reach its intended destination. This partly due to the fact that transmission providers make capacity allocations independently of one another (and often according to different decision-making timelines), partly due to strict confirmation deadlines, and partly due to the fact that such a point-to-point reservation may not be rescinded or modified once confirmed. In February, the WEQ Executive Committee established a task force to provide guidance regarding the scope of work to be performed by the WEQ OASIS subcommittee on standards to facilitate service across multiple transmission systems (SAMTS). Led by Alan Pritchard of Duke Energy, the task force considered several methodologies by which coordination could be accomplished. The group focused on addressing the key issues raised in relevant FERC proceedings, with the goals of providing transparency to the market and offering flexibility to transmission customers. The task force recommendation proposes that each affected transmission provider independently evaluate its portion of the linked request, with the opportunity for a trueup by the transmission customer once all evaluations are completed. Thus, the transmission customer, after submitting and monitoring requests on multiple systems, would communicate true-up information to each of the affected transmission providers. Targeted completion date of late 4Q 2010. · e-Tariff Implementation Guide The e-Tariff Implementation Guide, developed at NAESB and adopted by FERC, is used by electric, natural gas, and oil entities to assist in the filing of electronic tariffs with the Commission. FERC has made certain adjustments to this Implementation Guide which will require minor corrections to ensure that the NAESB standard is consistent. The most efficient way to accomplish consistency is by the use of the NAESB minor correction process. In the event that FERC makes a non-substantive change to the Guide, NAESB staff will initiate the minor correction process. Should a change be substantive, conference calls or face-to-face meetings will be held to process the change.

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Selected Provisional Items Approved by the NAESB Board of Directors: 1 Develop and or modify business practices related to support of NERC effort on the NERC Resources and Transmission Adequacy (Project 2009-05 Resource Adequacy Assessment). Determine any needed NAESB action in support of the Interchange Distribution Calculator (IDC) and develop any necessary standards. Prepare recommendations for future path for TLR (equity concerns) in concert with NERC, which may include alternative congestion management procedures. Work on this activity is dependent on completing 2010 WEQ Annual Plan 1.a (Parallel Flow Visualization/Mitigation for Reliability Coordinators in the Eastern Interconnection). Develop complementary standards that align with NERC Project 2008-01 Voltage and Reactive Control, for which a white paper is expected after the SAR is authorized to proceed by the NERC Standards Committee. Conduct assessment to determine if Electric Industry Requirements documented in WEQ-011 Gas / Electric Coordination should be considered reliability requirements and transition to NERC. Develop needed business practice standards for organization/company codes for NAESB standards ­ and address current issues on the use of DUNs numbers. Common code usage is linked to the transition of the Registry from NERC to NAESB.

3 4

5

9

10

Note Provisional Items 2, 7, 8, 11, and 12 have intentionally been omitted from this list. Provisional Item 6 has been added to the 2010 Annual Plan as Item No. 1(d)

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System Operator Subcommittee (SOS)

October 14-15, 2010 Biloxi, MS Rocky Williamson y SOS Chair

1

Outline

· Fall 2010 System Operator Conferences (two) · Overview of all four 2010 System Operator Conferences · 2010 Train-the-Trainer Workshop · 2011 System Operator Conferences planned

2

1

Fall 2010 System Operator Conferences Dates, Locations, Attendees

· Conference #3: September 14-16, 2010 Nashville/Franklin, TN 128 attendees representing 25 entities · Conference #4: September 21-23, 2010 Nashville/Franklin, TN 126 attendees representing 28 entities

3

Fall 2010 System Operator Conferences Entities Contributing Speakers or Facilitators

· AECI · EKPC · Entergy Transmission · Georgia Power Company · GSOC · NERC · PJM · PowerSouth · Prairie Power · SCE&G · SMEPA · Southern Company Services R li bilit C ti · SERC Reliability Corporation · TVA

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2

Fall 2010 System Operator Conferences Conference Agenda Highlights: Presentations

· Day 1: Contractor ­ SOS Intl, Charlotte, NC Power System Restoration Principles · Day 2: Industry SMEs Human Error Prevention, Three-Part Communication, Interchange Techniques, CIP Standards

5

Fall 2010 System Operator Conferences Agenda Highlights: Facilitator-led Exercises

· Day 2: Simulator blackstart drills · Day 3: RC, TOP, and BA round table exercises on restoration Knowledge check/learning assessment

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3

Fall 2010 System Operator Conferences CE Hours To Be Uploaded

· Conference #3 and #4 CE hours to be uploaded 4,788 CEHs · Facilitator training #3 and #4 hours to be uploaded 144 CEHs · Total CEHs to be uploaded for 2010 fall conferences (within 60 days) 4,932 CEHs

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Fall 2010 System Operator Conferences Preliminary Feedback

· Preliminary feedback: With about 45 responses, "overall conference experience" rating (scale of 1-5 with 5 the best): ­ Approval rating of 4.85 for conferences #3 and 4

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4

Overview of 2010 Conferences

· Conference #1 and #2 ­ Columbia, SC; April 20-22 and May 4-6 46 · Conference #3 and #4 ­ Nashville/Franklin, TN; September 14-16 and 21-23 Total participants: 504 Total number of SERC entities represented: 28 Total continuing education hours (CEHs) awarded: 9,706

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2010 Train-the-Trainer Workshop (Planned)

· December 1-2, 2010 at SERC offices, Charlotte, NC · Workshop title: PER Standards Compliance Preparation · Focus is on helping responsible entities prepare for existing and pending industry training standards 12-16 NERC-approved CE hours awarded Cost is $400-$500 per participant $400 $500 Firm commitments to date are 15 Please consider sending your trainers to this workshop: contact Margaret Stambach at [email protected]

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5

2011 System Operator Conferences Planned

· Conference #1: April 19-21, 2011 ­ Charlotte, NC · Conference #2: May 3-5, 2011 ­ Charlotte, NC · Conference #3: September 13-15, 2011 ­ Nashville/Franklin, TN · Conference #4: September 20-22, 2011 ­ Nashville/Franklin, TN · Registration on the SERC Web site will be available by midDecember, 2010

11

Questions?

12

6

NERC Personnel Subcommittee (PS) Update

October 14-15, 2010 Biloxi, MS Margaret Stambach, SERC Training Manager for g , g g Wayne Mitchell, SOS Vice Chair and SERC PS Rep

1

Outline

· PS meeting dates and locations · Deadline for CEH upload to SOCCED · CE program statistics · CE program manual · CE program audits

2

1

Personnel Subcommittee Meeting Dates & Locations

· Last meeting June 2-3, 2010, San Francisco, CA (hosted by Pacific G&E) · Next meeting October 13-14, Holyoke, MA (hosted by ISO New England) The following slides contain highlights from the last meeting on June 2 3 2010 i S F J 2-3, in San Francisco i

3

Deadline for CEH Upload to SOCCED

· All NERC-approved continuing education providers have been notified of an extension to the deadline for uploading CE hours they have awarded to the System Operator Certification & Continuing Education Database (SOCCED): From 30 days to 60 days

4

2

CE Program Statistics

· For Q1 2010 102,099 CE hours reported 3,162 courses available 738 courses reviewed · For Q1 2009 84,015 84 015 CE h hours reported t d 845 courses reviewed

5

CE Program Manual (Changes Added & Manual Revision Posted)

· More stringent requirements for becoming a NERC-approved provider Equivalent to a "Level 2" audit · Expanded definition of piloting Self-paced courses still require piloting by five peers to determine the number of CEHs to award Self-study courses having a set run-time do not require piloting. The run time = CE hours.

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3

CE Program Audits

· As of June 2010, all Q2 2009 course audits were complete · Q3 2009 course audits were partially complete · Q4 2009 course audits scheduled to start July 1st with October 1st completion date

7

Questions?

8

4

Available Transfer Capability Working Group (ATCWG)

October 14-15, 2010 Biloxi, MS DuShaune Carter ATCWG Chair

1

ATCWG Report

· Met routinely with members of the SERC OPS via WebEx to discuss the interpretation and monitoring of compliance for the transfer capability related NERC MOD Standards · Submitted a proposal to the SERC NTSG to investigate using their OASIS process to assist with compliance NTSG agreed to develop a process to coordinate monthly and yearly firm transactions on a monthly basis

2

1

ATCWG Report

· Held an OPS/ATCWG Mini-workshop with members of SERC Compliance staff to discuss MOD-001-1, MOD-028-1, and MOD-030-2 Standards · Currently evaluating which aspects of the standards, if any, the ATCWG would like to request a formal NERC Interpretation

3

ATCWG Report

· Have plans to administer a self certification survey for MOD001 ­ 009 Supplements and Procedures prior to December 31, 2010

4

2

Questions?

5

3

Real Time Real-Time Model Working Group Update

October 14-15, 2010 Biloxi, MS Robert Kingsmore RMWG Chair

1

RMWG Planned Activities

· Address the exchange line/transformer limits (this is difficult to agree on due to the widely differing philosophies, g y gp p implementations, etc.) · MISO and SPP will be storing their network model dumps on the SERC RMWG site in the near future · The RMWG may be offering other entities outside of SERC to store their model dumps on the SERC site providing they adhere t th appropriate SERC agreements and use th dh to the i t t d the prescribed RMWG formats (this offer will be made at the upcoming NERC Data Exchange Working Group)

2

1

Questions?

3

2

SERC Telecommunications Subcommittee Update

October 14-15, 2010 Biloxi, MS Ben Adams TSC Chair

1

SERC Hotline

· Efforts continue with Inter7 to have a successful fail over test · The maintenance contract is on hold until we have completed a successful fail over · All weekly test calls are being completed successfully

2

1

SERC Office Hotline

· A new hotline is being installed in the SERC office and should y be online by October 8, 2010.

3

Questions?

4

2

NERC Frequency Response Initiative

Robert W. Cummings - NERC Director of System Analysis and Reliability I iti ti d R li bilit Initiatives SERC Operating Committee October 15, 2010

2

Frequency Response Initiative

1

Frequency Response Concerns

3

Frequency Response is declining in Eastern Interconnection

· Various factors are influencing g · When is frequency response too low?

Primary Control Frequency Response is being withdrawn Primary inertial generation being supplanted by non-inertial resources ­ wind, solar, electronically coupled resources

· What is their response to frequency excursions? · What is their susceptibility to tripping during frequency excursions?

Load characteristics are changing

· Unknown frequency response characteristics · Current modeling is insufficient to analyze the phenomenon

Eastern Interconnection Mean Primary Frequency Response Trend

4

2

Eastern Interconnection Mean Primary Frequency Response ­ Projected

5

Frequency Response Basics

(Using a 1400 MW generation loss event as an example) Page 6

60.10 NERC Frequency Response = 1800 1600 1400 1200 1000 800 600 400 200 0 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 Time (Seconds) 2000 60.05

Pre Event Frequency

A

Gover rnor/Load Response (MW)

Generation Loss (MW) Frequency Freq enc Point A-FrequencyPoint B Freq enc

60.00 60 00 59.95

B

Settling Frequency: Primary Response is almost all deployed

59.90 59.85 59.80 59.75

C

Frequency Nadir: Generation and Load Response equals the generation loss

Slope of the dark green line illustrates the System Inertia (Generation and Load). The slope is P/(D+2H)

Governor Response Load Response Frequency

59.70 59.65 59.60

Frequency (Hz)

3

Frequency Performance

Arresting Period Rebound Period Recovery Period

Page 7

Florida Disturbance ­ Non-Local Impacts Non8

8

4

Classic Frequency Excursion Recovery

9

Frequency (Hz)

60.050 60.025 60.000 59.975 59.950 59.925 59.900 59.875 59.850 59.825 59.800 59.775 59.750

-30 0

Excursion Recovery

Recovery Completed, TV y p ,

A = 60.000

B = 59.874 C = 59.812

30

60

90

120

150

180

210

240

270

300

330

360

390

420

Time (Seconds)

Typical Frequency Traces Following a Unit Trip

10

5

Inertial Response Variability

11

High Inertia g

Light Inertia

WECC Hydro

6

WECC Steam

Retuned Hydro Governors

7

Importance of Deployment Rate

Page 15

20 GW of generating capacity (red) 25 GW of generating capacity (blue) 30 GW if generating capacity (green)

Frequency Response Sustainability

Page 16

Blue = frequency response is sustained Red = generator has a "slow" load controller returning to MW set-point

8

Frequency Response Analysis

17

Whys and Wherefores (things to examine)

· Deadband -- currently typical setting is at ±36 mHz

ERCOT greatly improved frequency response by reducing deadband to ± 16.6 mHz

· Steam turbine sliding pressure controls · Loading units to 100 percent of capacity · MW setpoints -- li it d ti t i t limited time of response f · Blocked governor response · Once-through boilers · Gas Turbine inverse response

18

ERCOT Experience

9

Governor response is proportional at the deadband reaching 5% at 3 Hz deviation

Frequency Grid Deviation Frequency Hz Hz Frequency Response MW Droop %

Governor response "Steps" to the 5% droop curve at the dead-band

Frequency Grid Deviation Frequency Hz Hz -0.04000 -0.03900 -0.03800 -0.03700 -0.03600 -0.03500 -0.03400 -0.03300 -0.03200 -0.03100 -0.03000 -0.02900 -0.02800 -0.02700 -0.02600 -0.02500 -0.02400 -0.02300 0 02300 -0.02200 -0.02100 -0.02000 -0.01900 -0.01800 -0.01700 -0.01600 59.96000 59.96100 59.96200 59.96300 59.96400 59.96500 59.96600 59.96700 59.96800 59.96900 59.97000 59.97100 59.97200 59.97300 59.97400 59.97500 59.97600 59.97700 59 97700 59.97800 59.97900 59.98000 59.98100 59.98200 59.98300 59.98400 Frequency Response MW 8.00000 7.80000 7.60000 7.40000 7.20000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0 00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 Droop % 5.00000% 5.00000% 5.00000% 5.00000% 5.00000% 100.00000% 100.00000% 100.00000% 100.00000% 100.00000% 100.00000% 100.00000% 100.00000% 100.00000% 100.00000% 100.00000% 100.00000% 100.00000% 100 00000% 100.00000% 100.00000% 100.00000% 100.00000% 100.00000% 100.00000% 100.00000%

19

-0.04000 -0.03900 -0.03800 -0.03700 -0.03600 -0.03500 -0.03400 -0.03300 -0.03200 -0.03100 -0.03000 -0.02900 -0.02800 -0.02700 -0.02600 -0.02500 -0.02400 -0.02300 0 02300 -0.02200 -0.02100 -0.02000 -0.01900 -0.01800 -0.01700 -0.01600

59.96000 59.96100 59.96200 59.96300 59.96400 59.96500 59.96600 59.96700 59.96800 59.96900 59.97000 59.97100 59.97200 59.97300 59.97400 59.97500 59.97600 59.97700 59 97700 59.97800 59.97900 59.98000 59.98100 59.98200 59.98300 59.98400

4.69287 8.52357% 4.49175 8.68258% 4.29064 8.85650% 4.08952 9.04752% 3.88840 9.25830% 3.68728 9.49208% 3.48617 9.75283% 3.28505 10.04551% 3.08393 10.37636% 2.88281 10.75338% 2.68170 11.18694% 2.48058 11.69081% 2.27946 12.28359% 2.07835 12.99110% 1.87723 13.85020% 1.67611 14.91548% 1.47499 16.27125% 1.27388 18.05512% 1 27388 18 05512% 1.07276 20.50786% 0.87164 24.09245% 0.67052 29.82737% 0.46941 40.47654% 0.26829 67.09147% 0.06717 100.00000% 0.00000 100.00000%

Dead-band

Dead-band

0.01666 Hz Dead-Band BAL-001-TRE-1 Implementation

0.036 Hz Dead-Band Common Industry Implementation 600 MW Steam Turbine 5% Droop Setting

Close up look at +/-0.0166 Hz Dead Band with No Step Implementation 600 MW Generator

20

Capability (MW) 600.000

Frequency Response

Deadband Setting 0.0166 Hz

150.00

100.00

50.00 MW Change

0.00

No Step response at dead-band.

-50.00

-100.00

-150.00 59.50 59.55 59.60 59.65 59.70 59.75 59.80 59.85 59.90 59.95 60.00 60.05 60.10 60.15 60.20 60.25 60.30 60.35 60.40 60.45 60.50 Hz Droop Setting 5.00%

10

Close up look at +/-0.036 Hz Dead Band with Step Implementation 600 MW Generator

Capability (MW) 600.000

Frequency Response

Deadband Setting 0.036 Hz

21

150.00

100.00

50.00 MW Change

0.00

Step response at dead-band.

-50.00

-100.00

-150.00 59.50 59.55 59.60 59.65 59.70 59.75 59.80 59.85 59.90 59.95 60.00 60.05 60.10 60.15 60.20 60.25 60.30 60.35 60.40 60.45 60.50 Hz Droop Setting 5.00%

ERCOT Frequency Profile Comparison

January through August of each Year 35000 30000 One Minute Occurances s 25000 20000 15000 10000 5000 0

22

59 .9 59 .9 1 59 .9 2 59 .9 3 59 .9 4 59 .9 5 59 .9 6 59 .9 7 59 .9 8 59 .9 9

2010

60 60 .0 1 60 .0 2 60 .0 3 60 .0 4 60 .0 5 60 .0 6 60 .0 7 60 .0 8 60 .0 9 60 .1

2008

11

January thru August 2008 0.036 db vs. 2010 0.016 db

MW Minute Movement of a 600 MW Unit @ 5% Droop 120000 368360.3 100000 2010 MW Response of 0.0166 db 23.89% Decrease in MW movement with lower deadband.

23

484006.0

2008 MW Response of 0.036 db

80000 MW

60000

40000

20000

0

2008 MW Response of 0.036 db

Same 600 MW unit - MW movement due to frequency each year.

FRI Objectives

24

Coordinate all NERC standards development and performance analysis activities related to frequency response and control f d t l Identify specific frequency-related reliability factors Identify root causes of changes in frequency response Identify practices and methods to address root causes Consider impacts of integration of new generation technologies (such as wind, solar, and significant nuclear expansion)

6 60 0 .0 1 60 .0 60 2 .0 3 60 .0 60 4 .0 5 60 .0 6 60 .0 7 60 .0 8 60 .0 9 60 .1

2010 MW Response of 0.0166 db

59 . 59 9 .9 1 59 .9 2 59 .9 59 3 .9 4 59 .9 5 59 .9 6 59 .9 59 7 .9 8 59 .9 9

12

FRI Objectives

25

Develop metrics and benchmarks to improve frequency response performance tracking Share lessons learned with the industry via outreach, alerts, and webinars Determine if performance-based frequency response standards are warranted

Near-Term Tasks Near26

Issue Recommendations (ROP § 810) and surveys to collect data and information for analysis Develop a clear set of common terms for use by NERC and industry ­ Near completion Analyze current and historical Primary and Secondary Control Response performance ­ what factors influence that performance Develop appropriate metrics for tracking frequency performance on each interconnection to monitor trends and performance

13

Near-Term Tasks Near27

Develop automated method for identifying frequency deviation events to be used for BAs to measure Primary Control Response ­ Evaluating CERTS FMA Tool Develop sustainable methods for automatically collecting, trending, and analyzing various elements of frequency p q y response and control for frequency deviation events

MidMid-Term Tasks

28

Explore and analyze what are appropriate frequency response and control performance requirements to maintain system reliability Determine appropriate minimum Bias settings for use in AGC systems as part of an overall Frequency Response and gy Control strategy Improve transient dynamic models of Primary Control Response for generators and other devices

14

LongerLonger-Term Tasks ­ 1 to 2 Years

29

Develop and implement mid-term dynamic models of Primary Control Response of generators and other devices

· Research required

Analyze current Inertial Response performance and determine what factors influence performance

LongerLonger-Term Tasks ­ 1 to 2 Years

30

Examine Primary Control Frequency Response characteristics of electronicallycoupled resources and "smart grid" loads smart grid · Develop load and "generator" models (research required) to properly analyze influence on system behavior in transient, post-transient, and mid-term stability Explore how displacement of inertial generation with electronically-coupled resources might influence Inertial Response

15

Reporting & Ongoing Activities

31

Ongoing Activities Communications / Educational Outreach

· T h i lR f Technical Reference D Documents t · Webinars / Workshops

Metrics & Calculations

· Ongoing determination of frequency events for analysis · Quarterly determination of response performance

Reporting on FRI Progress Oct. 18, 2010 ­ Report to FERC Dec. 31, 2010 ­ Report to Board February 2011 ­ Report to Board and FERC

2011 & 2012 Quarterly Reports to Board

32

Questions?

16

33

Generator Governor Survey

Survey Instructions

34

All generators rated 20 MVA or higher, or plants that aggregate to a total of 75 MVA or greater net rating at point of interconnection (i.e., wind farms, PV farms, etc.), Statement of Compliance Registry Criteria, Rev. 5.0.

­­ Jointly-owned units ­ reported by the operating entity.

Combined-cycle plants ­ combustion turbines and heatrecovery (steam turbine) units to be reported separately. Wind farms ­ report on a point-of-interconnection basis. If operable in more than one interconnection, complete the survey for operation in each of the interconnections.

17

Survey Instructions

35

1. Unit name and number. 2. Balancing Authority (BA) in which the generator is operated (pull-down).

­ a. If operable in more than one, please note all applicable BAs.

b. If operable in more than one interconnection, p , complete the survey for operation in each of the interconnections.

Survey Instructions

36

3. Unit seasonal Net MW ratings normally reported to NERC for resource adequacy analyses:

a. Summer Net MW rating ­ b. Winter Net MW rating

4. Prime mover (steam turbine, combustion turbine, wind turbine, etc. -- pull-down) 5. Fuel type (coal, oil, nuclear, etc. -- pull-down)

18

Survey Instructions

37

6. Unit inertia constant (H) as modeled in dynamics analyses ­ the combined kinetic energy of the generator and prime-mover in watt-seconds at rated speed divided by the VA (Volt-Ampere) base. 7. What are the annual run hours for the unit (data for f each of the last 3 years)? h f th l t )? 8. What is the continuous MW rating (Pmax) of the unit?

Survey Instructions

38

9. What percent of time does the unit run at Pmax or valves wide-open? wide open? a. 0 to 30 % b. 31 % to 60 % c. 61 % to 100 % 10. Equipped with a Governor? (Y/N) If not, no further answers are necessary.

19

Survey Instructions

39

11. If yes, is the governor operational? (Y/N with a comment box) If not, please explain. a. Is the governor normally in operation? (Y/N with a comment box) (even if not normally operated, the data on the governor is still needed) b. What is the normal governor mode of operation? (pull-down) c. Is the governor response sustainable for more than one minute if conditions remain outside of the deadband? (Y/N)

Survey Instructions

40

11. (continued) d. Are there any regulatory restrictions regarding the operation of the governor? This should cover nuclear regulation, environmental restrictions (water temperature, emissions), water flow, etc. e. Does the governor respond beyond the high/low operating limit (boiler blocks)? (Y/N) f. Is th f I the governor response li it d by the rate of limited b th t f change? (Y/N) g. Are there any other unit-level or plant-level control schemes that would override or limit governor performance? If yes, please explain.

20

Survey Instructions

41

12.Governor Type? Electronic (analog electro-hydraulic); electro hydraulic); DEH (digital electro hydraulic); Mechanical; Other -- please specify 13.Governor manufacturer and model?

a. If mixed vendor equipment is installed, please explain.

Survey Instructions

42

14.Governor Deadband setting?

a. Deadband in(+/-) mHz ( )

i. If in mHz is the deadband centered around a frequency reference (60 Hz or current frequency)?

b. Deadband in (+/-) RPM

i. ii. For RPM specify number of machine poles If in RPM, is the RPM reference nominal or current RPM?

c. What is the basis for this setting? d. Once activated, what are the conditions for which the governor action is reset?

21

Survey Instructions

43

15.What is the percentage (%) droop setting on the governor?

a. What is the basis for the droop setting?

16.Does the unit Frequency Response step into the droop curve or is it linear from the deadband?

Survey Instructions

44

17.Prime mover control mode ­ What is the normally used Turbine Control mode(s)? If more than one is prevalently used, select a primary and explain. Turbine manual Thermally-limited Turbine following Boiler following Part-load Pre-select MW set point Coordinated control Other (please explain)

22

Survey Instructions

45

18.Do market rules restrict or override governor speed controls? (Y/N) If yes, please explain.

Survey Instructions

46

For steam generator controls or central station controls: 19.Does the boiler control or combined cycle central station control have a frequency input? (Y/N) If yes, answer the following questions:

a. Deadband in(+/-) mHz

i. If in mHz is the deadband centered around a frequency reference (60 Hz or current frequency)?

b. Deadband in (+/-) RPM

i. ii. For RPM specify number of machine poles If in RPM, is the RPM reference nominal or current RPM?

c. What is the basis for this setting?

23

Survey Instructions

47

20.Does the control's Frequency Response step into the droop curve or is it linear from the deadband? 21.What is the steam turbine control mode? (boiler following, turbine following, coordinated control) 22.Do 22 Do the unit or plant controls over ride governor over-ride speed control or are the control parameters supportive? (Y/N)

Survey Instructions

48

23.Does the boiler operate under variable/sliding pressure? (Y/N)

a. What is the control/governor valve position percentage (%) during variable pressure operation?

24.Do unit or plant economic controls over-ride governor speed control? (Y/N)

24

Eastern Interconnection

49

0706

UTC Atlantic Standard Atlantic Daylight Eastern Standard Eastern Daylight Central Standard Central Daylight Mountain Standard Mountain Daylight Pacific Standard Pacific Daylight

306 406 206 306 106 206 2406 106 2306 2406

8-16-10 Braidwood Trip 1650

25

Event Performance Data Questions

51

Interconnection Eastern Western Texas Québec

Date 8/16/2010 8/12/2010 8/20/2010 12/10/2009

Time 1:06:15 14:44:03 14:25:29 15:09:31

Time Zone CST CST CST EST

Survey Instructions

52

25.Was the unit on-line during the event? (Y/N) 26.Pre event 26 Pre-event generation (MW) ­ Enter the MW output of the generator at the time just before the event began. 27.Post-event generation (MW) ­ Enter the MW output of the generator after the event that was reflects the response by the governor to the frequency deviation. 28.Time to achieve post-event response (seconds) ­ Enter the time (in seconds) it took to achieve the MW response in question 27.

26

State of NERC Standards Development and Results Based Standards

David Taylor Director of Standards Development SERC Reliability Corporation Operating Committee ( October 15, 2010 Biloxi, Biloxi MS

Agenda

Project 2008-06 Cyber Security Order 706 2008 06 Standard Processes Manual Results-based Reliability Standards Initiative y p Reliability Standards Development Plan Questions

CIP Version 4 ­ Status

Target completion ­ 4th Quarter 2010

· K 2010 NERC C Key Corporate G l t Goal

Industry survey conducted CIP Version 4 posted for formal comment thru October 20

· CIP-002-4 Attachment 1 · CIP-003-4 to CIP-009-4 conforming changes only · Ballot pool being assembled

Urgent Action SAR for CIP-005-4

3

Use of "Informal" Stakeholder Feedback

Unlimited feedback on "Preliminary" drafts Respond to all comments on "Final" draft p

Informal Comments

Preliminary Draft Standard Tech Meetings

Tech Conferences

Final Draft Standard

Checkbox Comment Form

45 Days No Restrictions Webinars

Emphasis on "Quality" Before g Posting Final Drafts

·Quality review required before "final draft" posted ·Results of review sent to Standards Committee and Drafting Team

Final Draft

Working Draft of Standard

Successive Ballots

Post Draft Standard for Formal Comment Period & Ballot

45 Day Formal Comment Period

Open to All Stakeholders

TOW RE Gov't SEU LEU Mkt RTO LSE TDU Gen

30 Days to Form Ballot Pool

10 Days For Initial Ballot

Results-based Reliability Standard Initiative Resultsy

Results-based Reliability Standards

· Process for drafting standards · Create a portfolio of performance, risk, and competency-based requirements p gy · Defense-in-depth strategy · Clear and measurable expected outcomes · Requirements structured in the form of who under who, what conditions (if any), shall perform what action, to achieve what particular result or outcome

8

Results-based Reliability Standard Initiative Resultsy

Building Barriers to Failure

Competency-Based Requirements Risk-Based Requirements Performance-Based Requirements

Success! Failure Avoided!

Tools Communications Personnel Qualifications Security Bulk Power System Maintenance Measures Testing Modeling Simulation Analysis Vegetation Management

9

Results-based Reliability Standard Initiative Results Implementation transferred to Standards Committee p Provided Preliminary Training to SDTs

· Project 2007-07 Vegetation Management ( j g g (Proof-of-Concept) p) · Project 2009-01 Disturbance and Sabotage Reporting

Provided New Formal Training to SDTs g

· Project 2008-01 Voltage and Reactive Planning and Control · Project 2010-14 Balancing Authority Reliability-based Control Standards Committee responsible for implementation of plan

Favorable mention in FERC Order on NERC Three-year Assessment issued Septe be 16 ssess e t ssued September 6 Industry Webinar to be held Wednesday, October 20

10

Project Overview Reliability Standard Development Plan

Annual project for revising Reliability Standard p Development Plan Serves as the foundation for NERC's standards development efforts for the immediate three-year three year horizon

· Communicates vision · Prioritizes and coordinates

revision or retirement of existing reliability standards development of new reliability standards

11

Summary of Changes e ab ty Sta da d e e op e t a Reliability Standard Development Plan

Major overhaul Considered comments resulting from July 6, 2010 FERC Technical Conference on standards development p p y Embraced prioritization tool developed by NERC Standards Committee Process Subcommittee results based Embraced transition plan for results-based reliability standards

12

Summary of Changes Reliability Standard Development Plan y p

13

Reliability Standard Development Plan

Posted for comment in August

· 11 sets of comments from 28 entities · Focus on project priority

Remaining Schedule

· Standards Committee approval in October · Board of Trustees approval in November · Fil with applicable regulatory authorities File ith li bl l t th iti

14

Question and Answer Session

Questions?

15

Thank You

David Taylor Director of Standards D Di fS d d Development l [email protected]

16

Standards Update

October 14-15, 2010 Biloxi, MS Pat Huntley y SERC Manager of Reliability Standards

Presentation Agenda

· NERC Standards process · SERC regional c te a review ( 0 0) S C eg o a criteria e e (2010) · Development of UFLS Standards NERC UFLS Standard SERC UFLS Standard · Updates to SERC standards Web page

1

NERC Standards Process

· NERC Standard processes manual Approved by FERC on September 7, 2010 pp y p , ANSI approved · New standards template Requirements and measures listed together Rationale text boxes · Greater use of "informal" stakeholder feedback · More emphasis on "quality" before posting final drafts · Concurrent commenting and balloting · Use of "successive" ballots to achieve consensus

SERC Regional Criteria Review (2010)

· SERC regional criteria approved at July 7, 2010 BEC meeting: Underfrequency Load Shedding (UFLS) · SERC regional criteria approved at September 23, 2010 BEC meeting: Special Protection Systems (SPS) - EC Under Voltage Load Shedding (UVLS) - EC Actual and Forecast Demands - EC Reliability Assessments - EC System Restoration Plan - OC Real-time Model Data Exchange Procedure - OC

2

SERC Regional Criteria Review (2010) (cont.)

· Documents determined to NOT be SERC regional criteria 4 EC documents 1 OC document · Document reviews on October 13, 2010 SC agenda Verification of Generator Real and Reactive Power Capability Supplement Contingency Reserve Policy Disturbance Reporting Procedures · Document reviews (DRS and RSSC) on October 14, 2010 EC agenda System Modeling Data Requirements Supplement

Development of NERC UFLS Standards

· Project 2007-01: PRC-006-1 (& EOP-003-1) · 14 Requirements include: PC UFLS Program Performance Requirements (25% mismatch) Design Assessment every five years UFLS entity to implement PC UFLS Program UFLS entity data to PC UFLS Database Response to UFLS entity comments on PC UFLS program · Draft 5 ballot period: September 24-October 4, 2010 Quorum: 85.71 %--the quorum has been reached Weighted segment vote: 81.72 % Ballot results: the standard will proceed to recirculation ballot

3

Development of SERC UFLS Standards

· Draft Regional Standard: PRC-006-SERC-01 · Uses new standard format · Six requirements: R1: PC include subregion as island R2: minimum scheme requirements (same as current, except 2.6) R3: simulations at 13%, 22%, and 25% mismatch R4: UFLS entities implement PC scheme ­ annual updates by May 1 2010 1, ­ changes to % load in scheme within 18 months ­ UFLS entity less then 100 MW - 1 step R5: PC provide UFLS data to SERC R6: GO provide UFLS data to SERC

Development of SERC UFLS Standards (cont.)

· Draft 5 comment posting period: September 21-October 21, 2010 Comment Form · Next steps ­ Drafting team meeting October 26-27, 2010 to resolve comments ­ Ballot draft 6 in late November ??

4

Updates to SERC Standards Web Page

· · · · · Standards page moved to Central Desktop: Standards Home SERC standards: Regional UFLS Standard Standards Committee: Scope and Minutes Standing Committee documents: table Upcoming events: calendar

Questions?

10

5

SERC OC/CIPC Meeting

CIP and Related Issues of Potential Interest to the Operating Committee

October 14-15, 2010 Biloxi, MS Boyd Nation Presentation y

SERC OC/CIPC Meeting

Standards Efforts

· Revised EOP-004/CIP-001 ­ combined effort on disturbance reporting, i l di sabotage; d di t b ti including b t does not i l d t include CIP-008 (yet?) · CIP-002-4 ­ introduces bright line criteria from next version of CIP standards into the old structure · CIP-010-1/CIP-011-1 (?) ­ will resume efforts shortly

1

SERC OC/CIPC Meeting

Congress Watch

· A bill has passed a House subcommittee that would give FERC the authority to i th th it t issue emergency standards t d d immediately or to issue ordinary standards after industry input, but that bill has not been introduced on the House floor. · The Senate would prefer a multi-sector bill, although the Markey bill is industry-specific. · No action seems imminent.

SERC OC/CIPC Meeting

Compliance Application Notices

· Mostly harmless, but then there's CAN-005 (and probably CAN-006 d CAN-007) CAN 006 and CAN 007) · Effectively allows NERC to unilaterally issue interpretations of standards

2

SERC OC/CIPC Meeting

NERC Alerts

· The latest Aurora alert was issued this week: Mostly design-oriented, but monitoring requirements and procedural changes will affect operations Not binding, but ... Acknowledgement of receipt and survey response to NERC required

SERC OC/CIPC Meeting

Questions?

3

Information

Thursday March 11, 2010

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