Operating Committee Meeting Presentations · ORS Vice Chair, Chris Pilong, has worked with the OC Real Time Assessment Task Force to develop the compliance guidance document that

Operating Committee Meeting

PresentationsSeptember 12-13, 2017 | Quebec City

*All presentations are posted with the written consent of the presenters.

Agenda Item 5.b Operating Committee Meeting

September 12-13, 2017 NERC Operating Committee

Sub-group Status Report

Group: Operating Reliability Subcommittee

Purpose: The Operating Reliability Subcommittee (ORS) assists the NERC Operating Committee (OC) in enhancing Bulk Electric System (BES) reliability by providing operational guidance to the industry; by providing oversight to the management of NERC-sponsored information technology tools and services which support operational coordination and by providing technical support and advice as requested.

Last Meeting: Sept. 6-7, 2017 Location: Toronto ON (hosted by IESO)

Duration: 1 Day

Next Meeting: November 8-9 Location: Birmingham AL (hosted by SERC)

Duration: 1 Day

Chair: Dave Devereaux – IESO

Vice-Chair: Chris Pilong - PJM

2017 Initiatives:

We continue to focus on regular review, update, and communication of Guidance Documents and Reference Guides within our area of responsibility. We also continue to prepare for implementation of the IDC PFV field trial and are working on several new, guideline development initiatives. Pending OC Approval Items:

ORS Recommendation to post the Draft Reliability Guideline – Gas and Electrical Operational Coordination Considerations for 45 day public comment. The NERC ORS sub-team will work to address or resolve any OC member comments and bring any needed revisions to the NERC OC September meeting for approval to post for public comment.

A joint ORS/CIPC task team has prepared a draft guideline: Reliability Guideline for Operator Recognition Cyber Intrusion into Operating System. The team is recommending that the draft be posted for OC and CIPC comment for 45 days. This will provide time to address any comments prior to OC/CIPC meetings in December.

Key issues for OC Resolution:

Reliability Coordinator Reliability Plan Reference Document – ORS has addressed comments received through the OC posting over the summer. In discussions with NERC Staff, it has been determined that the proposed NERC Certification checklist remains in very early stages of development. The ORS had understood that the two documents would be approved together. ORS seeks OC guidance on whether the reference document should be delayed.

Key Issues for OC Information:

ORS has endorsed and approved the current Florida Reliability Coordinating Council (FRCC) document for the FRCC Reliability Coordinator Area based on the nature of the minor revisions made to the existing plan. FRCC has re-formatted their document to align with Standards in effect since April 1, 2017. However, the plan did not make changes to any process, tools, or reporting relationships.

ORS has endorsed and approved the current Tennessee Valley Authority (TVA) document for the TVA Reliability Coordinator Area based on the nature of the minor revisions made to the existing plan. TVA has re-formatted their document to align with Standards in effect since April 1, 2017.

ORS continues to coordinate efforts with the RS to ensure the appropriate processes are in place to support future time error corrections if needed. ORS is also coordinating RC data collection to assist with RS-sponsored generator surveys.

ORS continues to receive updates from the EIDSN Steering Committee on the IDC Tool enhancements. Specifically, ORS has developed metrics that test the effectiveness of the Parallel Flow Visualization (PFV) project so that they can be incorporated into the field trial of the project. The PFV Project is intended to improve the data quality used by the IDC during curtailment of transactions and may eventually result in changes to both NERC Reliability Standards and NAESB Business Practices. Through EIDSN, the IDC Working Group is proceeding with a change order to incorporate the agreed to metrics. The project remains on schedule, with the field trial expected to begin on September 27.

Pseudo-Tie Coordination Reference Document – an ORS task team is working to address comments received. They expect to have a finalized version for the November ORS meeting, and will seek OC approval at the December OC meeting.

Dynamic Tag Exclusion Reference Document – an ORS task team is working to address comments received. They expect to have a finalized version for the November ORS meeting, and will seek OC approval at the December OC meeting.

NERC ORS RC representatives continue to work with NERC on planning activities for GridEx IV to be held in 2017. NERC staff continues to update and coordinate the exercise planning with the ORS.

Net Actual and Net Scheduled Interchange - In accordance with the OC’s motion at its March 2013 meeting, Peak Reliability RC and MISO RC have completed implementation of a project to share Net Scheduled and Net Actual Interchange to improve system operations resiliency. For the MISO hosted pilot, data quality and corroboration checks continue. In our last update, further development and access had been tabled until which time the application would transition to EIDSN. There are current plans to move this initiative to a web based portal application hosted by EIDSN at some point in the future. Since June, EIDSN has indicated that this transition may be delayed into 2018. As a result, MISO is examining what work they can continue in the interim.

ORS Vice Chair, Chris Pilong, has worked with the OC Real Time Assessment Task Force to develop the compliance guidance document that was approved by the OC since the last OC meeting to ensure that the guidance including ORS input.

ORS members discussed operational impacts and observations related to the recent solar eclipse. Final reports remain in development by the entities most impacted. All areas

reported demand reductions during the eclipse. This can be attributed to temperature drop and consumer behavior.

Current Initiatives/ Deliverables:

See pending approval items

ORS has reviewed and discussed the 2017 OC work plan and continues to work items in the plan as prioritized by the OC

Recurring Deliverables of Group

Provide subcommittee report for the regularly scheduled Operating Committee meetings.

Endorse or approve as applicable revisions to Reliability Plans.

Develop comments on the annual State of Reliability report.

Review the use of Proxy Flowgates.

Review TLR 5 events as requested.

Review of EEA events.

Develop comments on Adequate Level of Reliability metrics.

Provide coordination between the EIDSN IDC Steering Committee and the Operating Committee.

NERC Program’s Oversight Responsibility for the Group

Provide a forum for discussion of operating practices and potential lessons learned.

Provide a forum for discussion of information technology tools and services that facilitate operational reliability coordination.

Provide oversight and guidance on aspects of Interchange Scheduling, including Dynamic Transfers, as it applies to impacts on reliable operations.

NERC Document (Non-Reliability Standard) Responsibility for the Group

Guidelines and Reference Documents

Resource Subcommittee

UpdateTim Reynolds, Vice Chair

NERC Operating Committee

September 12-13, 2017

RELIABILITY | ACCOUNTABILITY2

• Frequency Work Group (FWG) Events were selected for March – April 2017 for all interconnections

Process document is in the final drafting stages for selecting BAL-003 and M-4 events

Work Group Updates


• Inadvertent Interchange Working Group (IIWG) Outreach done to BAs in the EI with greater then absolute value of 10,000

MW

Outreach has been successful to help manage

o Inadvertent Interchange

o Interconnection Time Error

Work Group Updates


• Reserves Working Group (RWG) Developed a form to collect data from Reserve Sharing Groups (RSG) and

individual BAs that do not participate in a RSG

Data will be used for

o Continued NERC RS performance evaluation

o FERC Order 835

o NERC PC approved M6 and M7 metrics for NERC State of Reliability Report

Data will be kept confidential according to NERC Rules of Procedures

Collection will be quarterly starting with Q1 in 2018, and will be due 15 days upon the end of the quarter

Work Group Updates


Work Group Updates


• Western Interconnection Selected event occurred on 08/08/2017

Survey request sent on 8/11/2017

o Contained information who to contact with questions

o Links to Recorded meeting and presentation

Responses are due on 09/11/2017

• Eastern Interconnection Expects to host a webinar late September

Select an event on early October

Generator Survey Update


• Interconnection Time Error All MTEC in the WI and EI were fast time error corrections

• ERS Measures 1, 2, 4, and 6 Each measure was reviewed at the last RS meeting

Measure 1 will be reviewed on a annual basis

The RS had proposed changed for Measure 4

• Interconnection Frequency Performance RMS charts were examined

o Largest RMS1 outliers in each interconnection were examined

o Information will be used to see if RS can find lessons learned for frequency variations

Other Updates


• BA Area Footprint Document Document to capture process that needs to happen when a BA changes

their footprint

Document is expected to be ready for RS review at the Oct 2017 meeting

• RS request for the IRPTF RS has request that the IRPTF examine as part of its system studies at

various levels of inverter penetration, provide the RS with results and recommendations as to whether the Western Interconnection Resource Loss Protection Criteria (RLPC) would need to be changed based on inverter-based performance characteristics as soon as possible.

Other Updates


NERC Lessons Learned Summary

Hassan HamdarOperating Committee MeetingSeptember 12, 2017


NERC Lessons Learned PostedJune – August 2017

• Three new NERC Lessons Learned (LL) were published since mid-June 2017: LL20170601 – “Generator Trip While Performing Frequency Response”

LL20170701 – “Loss of Wind Turbine due to Transient Voltage Disturbance on the BPS”

LL20170801 – “Auxiliary Power Loss to STATCOM Leads to UVLS Operation”


• Description Two units of a three-unit coal plant were at about half load when 1500

MW of generation tripped elsewhere.

LL20170601 – Generator Trip While Performing Frequency Response


• In response, both units rapidly increased their output: Unit 1 @205 MW/min ramp rate and Unit 3 @169 MW/min.

• Induced & Forced Draft fans did not respond in a coordinated manner to load demand.

• <15 seconds after the frequency dip, both units tripped due to low furnace pressure.



• In the past, the units rode through events like this and assisted system recovery.

• Accumulated plant mods and incremental tuning over the years had altered plant response - the Distributed Control System (DCS) was no longer “in tune” with the physical plant.

• This was a configuration management issue. Configuration management involves keeping the physical system (what is really there), the documented system (what is said to be there), and the requirements of the system (what is supposed to be there) in sync at all times.




• Corrective actions The GO worked with the DCS vendor to tune control curves for the fans

and other equipment. This was similar to performing an initial control system commissioning. The DCS tuning cost was less than the startup fuel costs that would have been realized as a result of each of the unnecessary unit trips.

• Lessons Learned Accumulated effects of plant modifications and incremental tuning

changes may significantly alter plant response over time. Eventually, the digital model in a DCS may no longer correspond to physical reality or system requirements.

It is cost effective to obtain unit load data and perform baseline “re-tuning” every 5-10 years (depending on frequency of modifications) or as part of any major modification project.


LL20170701 – Loss of Wind Turbine due to Transient Voltage Disturbance on the BPS

• Description Transmission system voltage disturbance events in Australia and Texas

have highlighted concerns with ride through capability for some wind turbine control systems

LL20170701 discusses the Sept. 28, 2016 South Australia Blackout and five events in Texas. It includes graphs, illustrations & links.

In the S.A. Blackout case, multiple voltage excursions in a short time resulted in 456 MW of wind generation disconnecting: wind generator voltage ride-through settings were set to disconnect when 3 to 6 events were detected within a given time frame.

Those parameter settings and some control system information were not in information provided to Australian Energy Market Operator during the registration process prior to interconnection.


Wind plant operators and turbine manufacturers improved voltage ride-through settings

A March 2017 event resulted in three transmission voltage disturbances w/in 1.6 seconds. All wind plants on the S.A. grid rode through, indicating that changes made since the Sept. 2016 event improved the ride-through characteristics of the wind plants.

• One Texas case involved multiple voltage excursions, losing 475 MW (130 turbines) due to the same issue seen in Australia, but did not result in a blackout.

• In two Texas cases, failed crowbar circuits caused wind turbines to trip.

• In one case, voltage disturbance magnitude ride-thru settings were found to be too tight.

• Another Texas case saw turbines trip due to UPS failures.




• Lessons Learned Wind generation owners should review and verify the voltage ride-through

capabilities of their equipment, clearly communicate those capabilities to their BA and connected TOPs, and ensure that the models provided to the BA and TOPs correctly reflect those capabilities.

If BAs and TOPs are notified by the wind generation owners that units lack ride through capability, BAs and TOPs should communicate to their RC.

o BAs, TOPs, and RC should consider in their daily resource plan the potential for the loss of these resources during transmission faults on the power system.

o BAs, TOPs, and RCs should take appropriate mitigating measures.



• Lessons Learned Wind generation owners should review and verify that UPS and “Smart

Crowbar” systems within the wind turbines are maintained and functioning properly.

High speed PMU data is critical for visibility into the magnitude of voltage disturbances related to the loss of wind turbines (or grid resources of any type).


LL20170801 – Auxiliary Power Loss to STATCOM Leads to UVLS Operation

• Description A voltage disturbance on the transmission system led to the loss of

redundant aux cooling power sources for a Static Synchronous Compensator (STATCOM), causing it to trip.

Both aux cooling power supplies were fed from the same high-voltage substation.

The loss of the STATCOM exacerbated a low-voltage condition and caused the loss of an 57 MVAR capacitor bank as well.

Voltage on the transmission bus the STATCOM was connected to lowered to 0.7 per unit.

UVLS relays on distribution feeders in the area (set at 0.85 pu for 2 sec) tripped, shedding 92 MW of firm load.


LL20170801 – Auxiliary Power Loss to STATCOM Leads to UVLS Operation

• Corrective actions An uninterruptible power supply (UPS) was installed to supply the

STATCOM auxiliary equipment.

• Lessons Learned Design philosophy for a device that protects BPS voltage should ensure

that a voltage disturbance cannot prevent the device from functioning as intended.

The auxiliary power system is critical to the proper operation of STATCOM equipment. The design should ensure that redundant auxiliary power sources are fed sources electrically separated from areas that need STATCOM voltage support. If that is not feasible, a UPS should be considered.


Lessons Learned Metrics

2010 2011 2012 2013 2014 2015 2016 2017 Total

FRCC 0 0 0 1 3 1 2 0 7

MRO 0 2 0 0 1 0 2 0 5

NERC 23 1 0 0 1 0 0 1 26

NPCC 0 5 2 5 4 10 6 2 34

RF 0 3 1 3 4 1 1 1 14

SERC 0 1 0 1 1 1 0 0 4

SPP 0 0 2 0 2 1 0 0 5

TRE 0 5 8 1 2 1 1 2 20

WECC 0 5 5 3 1 1 1 3 19

Total 23 22 18 14 19 16 13 9 134


On the NERC website,

Go to www.NERC.com > Click on the “Program Areas & Departments” tab and click “Reliability Risk Management”

Then on the left side menu under “Event Analysis” click “Lessons Learned”

Link to Lessons Learned

At the lower left corner of the NERC.com homepage

http://www.nerc.com/pa/rrm/ea/Pages/Lessons-Learned.aspx

At the lower left corner of the NERC.com homepage

Ways to Access Lessons Learned

http://www.nerc.com/




For more Information please contact:

[email protected] (via email)

2017-2018 Winter

Reliability AssessmentOverview and Preliminary Key Findings

Elliott Nethercutt

September 12-13 | Operating Committee Meeting


Reserve Margins are Sufficient for All Assessment Areas


• Seasonal weather projections point to a mild winter.

• Reliability-focused programs continue to be in effect for winter preparedness in several Assessment Areas NPCC-New England (ISO-NE): Pay-for-Performance; DR; Duel Fuel

FRCC: Winter Transmission Assessment & Operational Seasonal Study

TRE-ERCOT: Winter Weatherization Workshop & Generating Unit Winter Weather Readiness Guideline

• As this active hurricane season poses threats to infrastructure, NERC will continue examine potential impacts that could affect reliability for the winter season

• New reliability issues not anticipated with Aliso Canyon gas storage facility returning to service on a limited-basis

Key Findings


2017-18 WRA Schedule

Date Action

August 4 Final 2017 LTRA data due to NERC (data to be used for WRA)

August 11 NERC sends information (winter summary) request to RAS

August 25 Information (winter summary) updates due to NERC

August 25-31 NERC develops WRA data report using data from 2017 LTRA

August 31-September 8 NERC sends report to RAS for review

September 11-14 NERC responds to RAS comments

September 13-15 NERC initial Administrative review

September 18 – October 2 NERC publications review

October 2-10 PC Review

October 11-20 NERC responds to PC feedback; finalizes comment matrix

October 20 PC Webinar to review final report and comment matrix

October 23-27 PC Email vote to approve report

October 24-October 27 Report sent to publications for final review

October 27-November 3 NERC Executive Management Review of Report

November 7 Send to NERC Board of Trustees and MRC members

November 15 WRA Release


ERSWG Update

Essential Reliability Services Working Group

NERC OC/PC

September 12, 2017


• Balancing/Ramping Historical Analysis (Measure 6) Largely completed; will wrap up in Q4 2017

Based on analysis of hourly CPS1 values for each BA

o CPS1 data collection process and analysis method has been vetted by the OC Resources Subcommittee (RS)

o RS process includes outreach to BA when indicated by the analysis of trends

o RS is incorporating the rolling review of CPS1 metrics and BA outreach into their ongoing processes

RS will provide annual input to the PC Performance Analysis Subcommittee for inclusion in the State of Reliability Report

Historical Balancing/Ramping


Historical M6 - Western Interconnection

1

2 34

5


Historical M6 - Eastern Interconnection

1 2

3

4


• Balancing/Ramping Forward-Looking Analysis (Measure 6) Expected to be completed in Q4 2017

Developed a model for prospective identification of potential concerns

o Currently testing and refining process with volunteer BAs

o In review by the PC Reliability Assessment Subcommittee (RAS)

Necessary data collection will be administered by the RAS going forward

Results to be included in future Long-Term Reliability Assessment Reports

Forward-Looking Balancing/Ramping


• Frequency Response Historical Analysis (Measures 1-4) Will be completed in Q4 2017

o Collecting historical interconnection-level data from the four interconnections since June 2016

o Load damping factors under development for use in ROCOF ½ second calculations

o Value of collecting BA level inertia data is under review

Frequency metrics data collection process established

o Completed first pass at calculating frequency response metrics

o OC Resources Subcommittee (RS) is reviewing and refining the metrics

RS will manage the historical frequency response analysis going forward

o RS will provide input to PC’s Performance Analysis Subcommittee (PAS) and into annual State of Reliability Report

Historical Frequency Response


• Frequency Response Forward-Looking Analysis (Measures 1-4) Under active development

o Ongoing work with the interconnections on the development of frequency response models

o Plans for model development to complete by Q4 2017

Operational models and analysis to be completed in 2018

o Analysis included in Long-Term Reliability Assessment Reports starting in 2018

In the future, the PC Reliability Assessment Subcommittee (RAS) will provide oversight for Forward-Looking Frequency Response Analysis

Forward-Looking Frequency Response


• Distributed Energy Resources (DER) Submitted SAR for MOD-032 to address recommendation in DERTF report

o In the hands of the NERC Standards Committee - SAR comment period just closed

DER Data Collection Guideline is underway - to be completed Q4 2017

o Not to be confused with DER Data Modeling initiatives (but supports them)

o Policy Briefing summary will also be created - scheduled for Q1 2018

Developing WG scope for DER Forecasting to include a survey to identify current practices and issues

o To be completed Q4 2017

o Led by John Simonelli

Developing recommendation for OC/PC coordination of DER issues going forward

Distributed Energy Resources


• Balancing/Ramping (Measure 6) Historical analysis - Policy Briefing

Forward-looking analysis - Technical Brief on process, and Policy Briefing

• Frequency Response (Measures 1-4) Historical analysis process - Technical Brief

Forward-looking approach and model development - Technical Brief (Q1-2018)

• Distributed Energy Resources (DER) DER Data Collection Guideline

WG scope for DER Forecasting to include a survey to identify current practices and issues.

Expected 2017 Deliverables


NERC | Report Title | Report Date I

Operating Committee Charter

September 2017

NERC | Operating Committee Charter | September 2017 ii

Table of Contents

Preface ....................................................................................................................................................................... iv

Section 1 – Purpose.....................................................................................................................................................1

Section 2 – General Overview and Functions ..............................................................................................................2

1. General forum .....................................................................................................................................................2

2. Advice and recommendations ............................................................................................................................2

3. Support for other NERC programs ......................................................................................................................2

4. Review and approval of the Operating Committee Strategic Plan and Work Plan ............................................3

5. Review of foundational changes to interconnected operations ........................................................................3

6. Manage and coordinate documents such as: .....................................................................................................3

7. Opinions and interpretations ..............................................................................................................................3

Section 3 – Membership .............................................................................................................................................4

1. Goals ...................................................................................................................................................................4

2. Expectations ........................................................................................................................................................4

3. Representation. ..................................................................................................................................................4

4. Selection..............................................................................................................................................................4

5. Terms ..................................................................................................................................................................5

6. Resignations, Vacancies, and Nonparticipation ..................................................................................................5

7. Proxies .................................................................................................................................................................5

Section 4 – Meetings ...................................................................................................................................................6

1. Quorum ...............................................................................................................................................................6

2. Voting ..................................................................................................................................................................6

3. Antitrust Guidelines ............................................................................................................................................6

4. Open Meetings....................................................................................................................................................6

5. Confidential Sessions ..........................................................................................................................................6

Section 5 – Officers .....................................................................................................................................................7

1. Terms and conditions ..........................................................................................................................................7

2. Selection..............................................................................................................................................................7

Section 6 – Subcommittees ........................................................................................................................................8

1. Appointing subgroups .........................................................................................................................................8

2. Nominating subcommittee .................................................................................................................................8

Section 7 – Executive Committee ...............................................................................................................................9

1. Authorization ......................................................................................................................................................9

2. Membership ........................................................................................................................................................9

Table of Contents

NERC | Operating Committee Charter | September 2017 iii

3. Election Process ..................................................................................................................................................9

4. Terms ..................................................................................................................................................................9

Section 8 – Action Without A Meeting ..................................................................................................................... 10

Appendix 1 – Committee Members ......................................................................................................................... 11

Appendix 2 – Meeting Procedures .......................................................................................................................... 14

1. Voting Procedures for Motions ........................................................................................................................ 14

2. Minutes ............................................................................................................................................................ 14

3. Minority Opinions ............................................................................................................................................ 14

4. Personal Statements ........................................................................................................................................ 14

Appendix 3 –Approval Process for Deliverables ...................................................................................................... 15

1. Reliability Guidelines........................................................................................................................................ 15

2. Reference Documents...................................................................................................................................... 15

3. Policy Outreach ................................................................................................................................................ 16

NERC | Operating Committee Charter | September 2017 iv

Preface

The North American Electric Reliability Corporation (NERC) is a not-for-profit international regulatory authority whose mission is to assure the reliability of the bulk power system (BPS) in North America. NERC develops and enforces Reliability Standards; annually assesses seasonal and long‐term reliability; monitors the BPS through system awareness; and educates, trains, and certifies industry personnel. NERC’s area of responsibility spans the continental United States, Canada, and the northern portion of Baja California, Mexico. NERC is the electric reliability organization (ERO) for North America, subject to oversight by the Federal Energy Regulatory Commission (FERC) and governmental authorities in Canada. NERC’s jurisdiction includes users, owners, and operators of the BPS, which serves more than 334 million people. The North American BPS is divided into several assessment areas within the eight Regional Entity (RE) boundaries, as shown in the map and corresponding table below.

The Regional boundaries in this map are approximate. The highlighted area between SPP and SERC denotes overlap as some load-serving entities participate in one Region while associated transmission owners/operators participate in another.

FRCC Florida Reliability Coordinating Council

MRO Midwest Reliability Organization

NPCC Northeast Power Coordinating Council

RF ReliabilityFirst

SERC SERC Reliability Corporation

SPP RE Southwest Power Pool Regional Entity

Texas RE Texas Reliability Entity

WECC Western Electricity Coordinating Council

NERC | Operating Committee Charter | September 2017 1

Section 1 – Purpose

The purpose of the Operating Committee (OC) is to promote North American Bulk-Power System operational reliability excellence.


Section 2 – General Overview and Functions

1. General forum The OC provides a general forum for aggregating ideas and interests regarding the operations of the interconnected Bulk-Power Systems in North America.

2. Advice and recommendations The OC provides the Electric Reliability Organization (ERO) (stakeholders, Board of Trustees (Board), and staff) with advice, recommendations, and the collective and diverse opinions on matters related to interconnected operations to help the industry arrive at informed decisions.

3. Support for other NERC programs The OC provides technical advice and subject matter expert support to each of the NERC program areas, and serves as a forum to integrate the outputs of each ERO program area, including:

a. Reliability Assessments – Review reliability assessments, assure technical accuracy and completeness of results, and endorse approval of assessments to NERC’s Board.

b. Emerging Issues and Reliability Concerns – Identify emerging issues within the electric industry, address issues in reliability assessments, and address other issues as assigned by the Board.

c. Operational Analyses – Develop operational analyses, model validation, and key reliability areas, resulting in technically accurate and comprehensive reports addressing these areas (i.e., frequency response, intermittent generation, distributed energy resources (DER), etc.). Provide recommendations that facilitate addressing the reliability risks identified. Provide oversight, guidance, and direction to address key planning related issues.

d. Standards Input – Provide technical expertise and feedback to Standard Authorization Requests (SARs) that have reliability-related impacts, provide foundational technical efforts that support the key reliability operational related standards development, coordinate effectively with the Standards Committee to maintain alignment on priorities of related OC efforts, develop and vet operational guidelines that align with approved standards with industry stakeholders, and provide reliability risk information for prioritization of SARs and new Reliability Standards.

e. Metrics – Provide direction, technical oversight, and feedback on the NERC Adequate Level of Reliability (ALR) metrics.

f. Event Analysis – Review all event reports to determine lessons learned and good industry practices and promote the dissemination of information to the industry to enhance reliability.

g. NERC Alerts – Participate in the review and development of requests for industry actions and informational responses.

h. Reliability Guidelines and Technical Reports – Develop reliability guidelines, white papers, technical reports and reference documents to address emerging issues and industry concerns related to system operations.

i. System Operator Training – Provide necessary support and guidance to facilitate System Operator training.

Section 2 – General Overview and Functions


4. Review and approval of the Operating Committee Strategic Plan and Work Plan The OC will develop, maintain and approve a strategic plan and associated work plan to address the functions of the OC. The strategic plan will be revisited as needed to maintain alignment with the NERC ERO enterprise. The work plan will be updated as needed to track the progress of the OC and subcommittees.

5. Review of foundational changes to interconnected operations The OC will review and provide constructive feedback regarding foundational changes to interconnected operations, such as changes to the footprints of reliability coordinators, balancing authorities, transmission operators, Interconnections, field tests and HVDC ties, etc.

6. Manage and coordinate documents such as:

a. State of Reliability Report

b. Technical content of the NERC Reliability Functional Model

c. Reliability Guidelines (See Appendix 3)

d. Reference Documents (See Appendix 3)

e. Other documents under the purview of the Operating Committee.

7. Opinions and interpretations The OC provides technical opinions at the industry stakeholders’ request on operating reliability concepts, philosophies, and standards.


Section 3 – Membership

1. Goals The OC provides for balanced decision making by bringing together a wide diversity of opinions from industry experts with outstanding technical knowledge and experience in the area of interconnected systems operation reliability.

2. Expectations OC voting members are expected to:

a. Bring subject matter expertise to the OC;

b. Be knowledgeable in reliable operations within their organization;

c. Attend and participate in all OC meetings;

d. Express their own opinions, as well as the opinions of the sector they represent, at committee meetings;

e. Complete committee assignments; and,

f. Inform the secretary of any changes in their status that may affect their eligibility for committee membership. Failure to do so in a timely manner may result in the member’s dismissal by the chair.

3. Representation. See Appendix 1, “Committee Members”

a. Committee members may, but need not, be NERC members. A non-voting representative must meet the requirements defined in Appendix 1. Voting members, with the exception of sector 11 that appoints its members, may hold a position in any sector in which they would be eligible for NERC membership, even if they are a NERC member in another sector. Questions regarding eligibility for committee membership will be referred to the NERC general counsel for final determination of status.

b. To ensure adequate Canadian representation, the membership to the committee may be increased so that the number of Canadian voting members is equal to the percentage of the net energy for load (NEL) of Canada to the total NEL of the United States and Canada, times the total number of voting members on the committee, rounded to the next whole number.

4. Selection With the exception of sector 11, NERC sector members will annually elect voting committee members to committee sectors corresponding to their NERC sector under an election process that is open, inclusive, and fair. The selection process will be completed in time for the secretary to send the committee membership list to the Board for its approval at the Board’s August meeting so that new committee members may be seated at the September meeting.

a. Un-nominated voting member positions will remain vacant until the next annual or special election. If a vacancy in an elected sector is created by a resignation or other cause, a special election will be held unless it would coincide with the annual election process. Special elections shall follow the same procedure as the annual election.

b. Members may not represent more than one committee sector at any one time.

c. A particular organization, including its affiliates, may not have more than one member on the committee.

Section 3 – Membership


d. If additional Canadian members are added, no more than one additional Canadian voting member shall be selected from a sector unless this limitation precludes the addition of the number of additional Canadian voting representatives required by Section 3.3.b. In this case, no more than two additional Canadian voting members may be selected from the same sector.

e. The secretary will monitor the committee selection process to ensure that membership specifications are met.

f. After the secretary announces the election results, the newly elected members will serve on the committee pending approval by the Board. The secretary will submit the newly elected members’ names to the Board for approval at the Board’s next regular meeting.

5. Terms Members’ terms are staggered, with one-half of the members’ terms expiring each year. Except for the cases described below, a member’s term is two years. Members may be re-elected for subsequent terms. Shorter terms may be required for several reasons:

a. If two members are simultaneously selected to a sector that did not have any existing members, in order to stagger their terms, one member will be assigned a one-year term and the second member will be assigned a two-year term using a fair and unbiased method.

b. If a member replaces a departed member between elections, the new member will assume the remaining term of the departed member.

c. If a member fills a vacant member position between elections, his/her term will end when the term for that vacant position ends.

6. Resignations, Vacancies, and Nonparticipation

a. Members who resign will be replaced for the time remaining in the member’s term. Members will be replaced pursuant to Section 3.4, officers will be replaced pursuant to Section 5, and executive committee members will be replaced pursuant to Section 7.

b. Newly elected or appointed members will serve on the committee pending approval by the Board. The secretary will submit new members’ names to the Board for approval at the Board’s next regular meeting.

c. The committee chair will contact any member who has missed two consecutive meetings (even if the member has sent a proxy) to 1) seek a commitment to actively participate or 2) ask the member to resign from the committee.

d. The chair may remove any member who has missed two consecutive meetings (even with a proxy).

7. Proxies A member of the committee may give a proxy only to a person who:

a. Meets the member’s eligibility requirements (see Section 3.3a) and is not affiliated with the same organization as another committee member (see Section 3.4c), or

b. Is not another committee member, unless that committee member would represent the proxy’s sector instead of his/her own sector at the meeting.

To permit time to determine a proxy’s eligibility, proxies must be submitted to the secretary in writing at least one week prior to the meeting (electronic transmittal is acceptable). Any proxy submitted after that time will be accepted at the chair’s discretion, provided that the chair believes the proxy meets the eligibility requirements.


Section 4 – Meetings

See Appendix 2, “Meeting Procedures.” In the absence of specific provisions in the Charter document, the OC will follow Roberts Rules of Order, Newly Revised.

1. Quorum A quorum requires two-thirds of the voting members.

2. Voting Except for sector 11, each voting member of the committee shall have one vote on any matter coming before the committee that requires a vote. Sector 11 voting is specified in Appendix 1. Actions by members of the committee shall be approved upon receipt of the affirmative vote of two-thirds of the voting members of the committee present and voting, in person or by proxy, at any meeting at which a quorum is present. The chair and vice chair may vote. Additional voting guidelines are in Appendix 2. Voting may take place during regularly scheduled in-person meetings or may take place via electronic mail, facsimile or conference call.

3. Antitrust Guidelines All persons attending or otherwise participating in the committee meeting shall act in accordance with NERC’s Antitrust Compliance Guidelines at all times during the meeting. A copy of the NERC Antitrust Compliance Guidelines statement shall be included with each meeting agenda.

4. Open Meetings NERC committee meetings shall be open to the public, except as noted below under Confidential Sessions. Although meetings are open, only voting members may offer and act on motions.

5. Confidential Sessions The chair of a committee may limit attendance at a meeting or portion of a meeting, based on confidentiality of the information to be disclosed at the meeting. Such limitations should be applied sparingly and on a non-discriminatory basis as needed to protect information that is sensitive to one or more parties. A preference, where possible, is to avoid the disclosure of sensitive or confidential information so that meetings may remain open at all times. Confidentiality agreements may also be applied as necessary to protect sensitive information.


Section 5 – Officers

1. Terms and conditions At its June meeting and every two years thereafter, the committee shall select a chair and vice chair from among its voting members by majority vote of the members of the committee to serve as chair and vice chair of the committee from the end of that June meeting until the end of the June meeting two years later. The newly selected chair and vice chair shall not be representatives of the same sector.

a. Pending approval by the Board, the newly elected officers will assume their duties as stated above. The secretary will submit the names of the elected officers to the chair of the Board for approval at the Board’s next regular meeting.

b. The chair and vice chair, upon assuming such positions, shall cease to act as representatives of the sectors that elected them as representatives to the committee and shall thereafter be responsible for acting in the best interests of the members as a whole.

2. Selection The committee selects officers using the following process. The chair is selected first, followed by the vice chair.

a. The nominating subcommittee will present its recommended candidate.

b. The chair opens the floor for nominations.

c. After receiving, or hearing no further nominations, the chair closes the nominating process.

d. The committee will then vote on the candidate recommended by the nominating subcommittee, followed by the candidates nominated from the floor in the order in which they were nominated. The first candidate to garner the majority of the committee’s votes will be selected.

e. If the committee nominates one person, that person is automatically selected as the next chair.

f. If the committee nominates two or more persons, and none receive a majority of the committee’s votes, then the secretary will distribute paper ballots for the members to mark their preference.

g. The secretary will collect the ballots. If the committee nominates three or more candidates, then the winner will be selected using the Instant Runoff Process. (Explained in Roberts Rules of Order).


Section 6 – Subcommittees

1. Appointing subgroups The OC may appoint technical subcommittees, task forces, and working groups as needed. Once these subgroups have been appointed, a scope document will be developed to ensure alignment with the Operating Committee Charter and strategic plan. The OC will annually review the appropriateness of ongoing subcommittees, task forces, and working groups.

2. Nominating subcommittee At the first regular meeting following the selection of a new committee chair, the chair will nominate, for the committee’s approval, a slate of five committee members from different sectors to serve as a nominating subcommittee. The subcommittee will:

a. Recommend candidates for the committee’s chair and vice chair, and

b. Recommend candidates for the executive committee’s four “at large” members.


Section 7 – Executive Committee

1. Authorization The executive committee of the OC is authorized by the OC to act on its behalf between regular meetings on matters where urgent actions are crucial and full committee discussions are not practical. Ultimate OC responsibility resides with its full membership whose decisions cannot be overturned by the executive committee, and which retains the authority to ratify, modify, or annul executive committee actions.

2. Membership The committee will elect an executive committee of six members, all from different sectors, as follows:

a. Chair

b. Vice-chair

c. Four at-large members from different sectors nominated by the nominating subcommittee

3. Election Process The nominating subcommittee will present its slate of candidates for the four “at large” members.

a. The chair opens the floor for additional nominations.

b. If the Committee members nominate additional candidates, then the secretary will distribute paper ballots for the members to list their top four candidates.

c. The four candidates who receive the most votes will be elected, provided that no two candidates may be from the same sector.

4. Terms The executive committee will be replaced every two years, with the chair and vice chair replaced at a June meeting and the at-large members replaced at a September meeting.


Section 8 – Action Without A Meeting

The OC may act by mail or electronic (facsimile or e-mail) ballot without a regularly scheduled meeting. Two- thirds of the members present and voting is required to approve any action. A quorum for actions without a meeting is two-thirds of the OC members. The OC chair or four members (each from different industry segments) may initiate the request for such action without a meeting. The secretary shall post a notice on the NERC website and shall provide OC members with a written notice (letter, facsimile, or e-mail) of the subject matter for action not less than five business days prior to the date on which the action is to be voted. The secretary shall distribute a written notice to the OC (letter, facsimile, or e-mail) of the results of such action within five business days following the vote and also post the notice on the NERC website. The secretary shall keep a record of all responses (e-mail, facsimiles, etc.) from the OC members with the OC minutes.


Appendix 1 – Committee Members

Committee Members Name Definition Members

Voting Members

1. Investor-owned utility This sector includes any investor-owned entity with substantial business interest in ownership and/or operation in any of the asset categories of generation, transmission, or distribution. This sector also includes organizations that represent the interests of such entities.

2

2. State/municipal utility This sector includes any entity owned by or subject to the governmental authority of a state or municipality, that is engaged in the generation, delivery, and/or sale of electric power to end-use customers primarily within the political boundaries of the state or municipality; and any entity, whose members are municipalities, formed under state law for the purpose of generating, transmitting, or purchasing electricity for sale at wholesale to their members. This sector also includes organizations that represent the interests of such entities.

2

3. Cooperative utility This sector includes any non-governmental entity that is incorporated under the laws of the state in which it operates, is owned by and provides electric service to end- use customers at cost, and is governed by a board of directors that is elected by the membership of the entity; and any non-governmental entity owned by and which provides generation and/or transmission service to such entities. This sector also includes organizations that represent the interests of such entities.

2

4. Federal or provincial utility/Federal Power Marketing Administration

This sector includes any U.S. federal, Canadian provincial, or Mexican entity that owns and/or operates electric facilities in any of the asset categories of generation, transmission, or distribution; or that functions as a power marketer or power marketing administrator. This sector also includes organizations that represent the interests of such entities. One member will be a U.S. federal entity and one will be a Canadian provincial entity.

2

5. Transmission dependent utility

This sector includes any entity with a regulatory, contractual, or other legal obligation to serve wholesale aggregators or customers or end-use customers and that depends primarily on the transmission systems of third parties to provide this service. This sector also includes organizations that represent the interests of such entities.

2

6. Merchant electricity generator

This sector includes any entity that owns or operates an electricity generating facility that is not included in an investor-owned utility’s rate base and that does not otherwise fall within any of sectors (i) through (v). This sector includes but is not limited to cogenerators, small power producers, and all other non-utility electricity producers such as exempt wholesale generators who sell electricity at wholesale. This sector also includes organizations that represent the interests of such

2




entities.

7. Electricity marketer This sector includes any entity that is engaged in the activity of buying and selling of wholesale electric power in North America on a physical or financial basis. This sector also includes organizations that represent the interests of such entities.

2

8. Large end-use electricity customer

This sector includes any entity in North America with at least one service delivery taken at 50 kV or higher (radial supply or facilities dedicated to serve customers) that is not purchased for resale; and any single end-use customer with an average aggregated service load (not purchased for resale) of at least 50,000 MWh annually, excluding cogeneration or other back feed to the serving utility. This sector also includes organizations that represent the interests of such entities.

2

9. Small end-use electricity customer

This sector includes any person or entity within North America that takes service below 50 kV; and any single end- use customer with an average aggregated service load (not purchased for resale) of less than 50,000 MWh annually, excluding cogeneration or other back feed to the serving utility. This sector also includes organizations (including state consumer advocates) that represent the interests of such entities.

2

10. Independent system operator/Regional transmission organization

This sector includes any entity authorized by the Commission to function as an independent transmission system operator, a Regional transmission organization, or a similar organization; comparable entities in Canada and Mexico; and the Electric Reliability Council of Texas or its successor. This sector also includes organizations that represent the interests of such entities.

2

11. Regional Entity This sector includes any Regional Entity as defined in Article I, Section 1, of the Bylaws of the corporation. In aggregate, this sector will have voting strength equivalent to two members. The voting weight of each Regional member’s vote will be set such that the sum of the weight of all available Regional Entity members’ votes is two votes.

2

12. State government This sector includes any state government department or agency in the United States having a regulatory and/or policy interest in the Bulk Electric System (BES).

2

Officers Chair and Vice Chair 2

Non-Voting Members

Government Representatives This sector includes any federal, state, or provincial government department or agency in North America having a regulatory and/or policy interest in wholesale electricity. Entities with regulatory oversight over the Corporation or any Regional Entity, including U.S., Canadian, and Mexican federal agencies and any provincial entity in Canada having statutory oversight over the Corporation or a Regional Entity with respect to the approval and/or enforcement of Reliability Standards, may be non-voting members of this sector.




United States federal government 2

Canadian federal government 1

Provincial government 1

Secretary The committee secretary will be seated at the committee table 1

Subcommittee Chairs The chairs of the subcommittees will be seated at the committee table.


Appendix 2 – Meeting Procedures

1. Voting Procedures for Motions

a. The default procedure is a voice vote.

b. If the chair believes the voice vote is not conclusive, the chair may call for a show of hands.

c. The chair will not specifically ask those who are abstaining to identify themselves when voting by voice or a show of hands.

d. The committee may conduct a roll-call vote in those situations that need a record of each member’s vote.

i. The committee must approve conducting a roll call vote for the motion.

ii. The secretary will call each member’s name.

iii. Members answer “yes,” or “no,” but may answer “present” if they wish to abstain from voting.

2. Minutes

a. Meeting minutes are a record of what the committee did, not what its members said.

b. Minutes should list discussion points where appropriate, but should usually not attribute comments to individuals. It is acceptable to cite the chair’s directions, summaries, and assignments.

c. Do not list the person who seconds a motion.

d. Do not record (or even ask for) abstentions.

3. Minority Opinions All Committee members are afforded the opportunity to provide alternative views on an issue. The meeting minutes will provide an exhibit to record minority opinions. The chair shall report both the majority and any minority views in presenting results to the Board.

4. Personal Statements The minutes will also provide an exhibit to record personal statements.


Appendix 3 –Approval Process for Deliverables

1. Reliability Guidelines. Reliability guidelines are documents that suggest approaches or behavior in a given technical area for the purpose of improving reliability. Reliability guidelines are not binding norms or mandatory requirements. Reliability guidelines may be adopted by a responsible entity in accordance with its own facts and circumstances.1

a. Approval of Reliability Guidelines

Because reliability guidelines contain suggestions that may result in actions by responsible entities, those suggestions must be thoroughly vetted before a new or updated guideline receives approval by the OC. The process described below will be followed by the OC:

i. New/updated draft guideline approved for industry posting. The OC approves for posting for industry comment the release of a new or updated draft guideline developed by one of its subgroups or the committee as a whole.

ii. Post draft guideline for industry comment. The draft guideline is posted as “for industry-wide comment” for forty-five (45) days. If the draft guideline is an update, a redline version against the previous version must also be posted.

iii. Post industry comments and responses. After the public comment period, the OC will post the comments received as well as its responses to the comments. The committee may delegate the preparation of responses to a committee subgroup.

iv. New/updated guideline approval and posting. A new or updated guideline which considers the comments received, is approved by the OC and posted as “Approved” on the NERC website. Updates must include a revision history and a redline version against the previous version.

v. Guideline updates. After posting a new or updated guideline, the OC will continue to accept comments from the industry via a web-based forum where commenters may post their comments.

(1) Each quarter, the OC will review the comments received. At any time, the OC may decide to update the guideline based on the comments received or on changes in the industry that necessitate an update.

(2) Updating an existing guideline will require that a draft updated guideline be approved by the OC in the above steps.

b. Review of Approved Reliability Guidelines

Approved reliability guidelines shall be reviewed for continued applicability by the OC at a minimum of every third year since the last revision

2. Reference Documents Reference documents provide information in a given technical area for the purpose of improving reliability. Reference documents are not binding norms or mandatory requirements.

Approval of reference documents.

Because reference documents contain suggestions that may result in actions by responsible entities, those suggestions must be thoroughly vetted by the committee before a new or updated reference document receives approval by the OC.

1 Standards Committee authorization is required for a reliability guideline to become a supporting document that is posted with or

referenced from a NERC Reliability Standard. See Appendix 3A in the NERC’s Rules of Procedure under “Supporting Documents.”

Appendix 3 –Approval Process for Deliverables


Approved reference documents shall be reviewed for continued applicability by the OC at a minimum of every third year since the last revision. Any comments received from industry since the last revision will be considered during the review.

3. Policy Outreach The OC will continue to coordinate with the forums, policymakers, and other entities to assure the reliability guidelines, reference documents and lessons learned are beneficially used throughout the industry. The OC Strategic Plan will contain details on the implementation of policy outreach.

NERC | Report Title | Report Date I

Operating Committee Strategic Plan September 2017

NERC | Operating Committee Strategic Plan | September 2017 ii

Table of Contents

Preface ....................................................................................................................................................................... iii

Introduction ............................................................................................................................................................... iv

Operating Committee Strategic Plan ..........................................................................................................................1

Purpose of Strategic Plan ........................................................................................................................................1

Guiding Principles ...................................................................................................................................................1

Operating Committee Goals .......................................................................................................................................2

Goal – OC 1 .............................................................................................................................................................2

Action Plan – OC 1 ...............................................................................................................................................2

Goal – OC 2 .............................................................................................................................................................2

Action Plan – OC 2 ...............................................................................................................................................2

Goal – OC 3 .............................................................................................................................................................3

Action Plan – OC 3 ...............................................................................................................................................3

Goal – OC 4 .............................................................................................................................................................4

Action Plan – OC 4 ...............................................................................................................................................4

Goal – OC 5 .............................................................................................................................................................4

Action Plan – OC 5 ...............................................................................................................................................4

NERC | Operating Committee Strategic Plan | September 2017 iii

Preface

The North American Electric Reliability Corporation (NERC) is a not-for-profit international regulatory authority whose mission is to assure the reliability and security of the bulk power system (BPS) in North America. NERC develops and enforces Reliability Standards; annually assesses seasonal and long‐term reliability; monitors the BPS through system awareness; and educates, trains, and certifies industry personnel. NERC’s area of responsibility spans the continental United States, Canada, and the northern portion of Baja California, Mexico. NERC is the Electric Reliability Organization (ERO) for North America, subject to oversight by the Federal Energy Regulatory Commission (FERC) and governmental authorities in Canada. NERC’s jurisdiction includes users, owners, and operators of the BPS, which serves more than 334 million people. The North American BPS is divided into eight Regional Entity (RE) boundaries as shown in the map and corresponding table below.

The highlighted areas denote overlap as some load-serving entities participate in one Region while associated transmission owners/operators participate in another.

FRCC Florida Reliability Coordinating Council

MRO Midwest Reliability Organization

NPCC Northeast Power Coordinating Council

RF ReliabilityFirst

SERC SERC Reliability Corporation

SPP RE Southwest Power Pool Regional Entity

Texas RE Texas Reliability Entity

WECC Western Electricity Coordinating Council

NERC | Operating Committee Strategic Plan | September 2017 iv

Introduction

The NERC Operating Committee (OC) is a stakeholder committee chartered by the NERC Board of Trustees (Board) to proactively support the NERC Enterprise mission. This strategic plan provides the OC with a clearly focused five-year road map for enhanced Bulk Electric System (BES) reliability, including alignment with the NERC top priorities as they continue to evolve over time. This plan is intended to guide the functions and core mission of the OC, providing a sustainable set of expectations and deliverables for the OC to assess and enhance operational reliability of the BES. It is not intended for this strategic plan to remain static throughout a five-year timeframe. Rather, it is crucial that the plan retain the flexibility to address emerging issues. As such, the OC will review the goals and specific items as necessary or, at least once every two years. This plan, along with its goals and measures, will be reviewed during OC meetings, and enhancements to the plan will be made as required to achieve the goal of promoting reliability. The OC and its subgroups will be actively engaged in promoting operational reliability excellence. Recognized as industry experts, the OC should be sought for expertise in training and guidance documents and assessments of system events and causal analyses, as well as standards recommendations, reviews, interpretations, and assessments. The OC focus will be centered on operating and maintaining the BES within secure limits during the operational planning and real-time periods on an actual and projected post-contingent basis to preserve the effectiveness of the BES.

NERC | Operating Committee Strategic Plan | September 2017 1

Operating Committee Strategic Plan

Purpose of Strategic Plan The NERC OC’s Strategic Plan’s purpose is to establish strategic direction for the NERC OC, in conjunction with the ERO’s vision. The Plan seeks to focus the OC on operational reliability matters and outlines the Guiding Principles under which the NERC OC will utilize for the next five years.

Guiding Principles

Coordinate with the Reliability Issues Steering Committee (RISC) on priorities and align the OC strategic plan with ERO’s strategic plan.

Maintain a focus on identification, analyses and mitigation of existing and emerging reliability risks.

Continually strive for the development and dissemination of high quality lessons learned through event analysis (EA), emerging cause code trending and information sharing.

Maintain relationships with other NERC standing committees and other forums.

Maintain and enhance reliability through the pursuit of clear NERC Reliability Standards, Reliability Guidelines, NERC Alerts, interpretations, lessons learned, and other operational compliance clarifications.

Maintain high levels of industry specific expertise to provide sound conclusions and opinions on operational issues.

Provide industry outreach through coordination with the forums, policymakers, and other entities to assure the reliability guidelines, reference documents and lessons learned are effectively publicized and made available throughout the industry.

Incorporate an operational perspective into NERC reports being issued to industry.

Assess effectiveness of system operators training program


Operating Committee Goals

Goal – OC 1 Investigate, review, and assess existing and emerging issues to identify gaps impacting the reliability of the BES and associated NERC Reliability Standards. The OC will engage in the identification and communication of reliability risks and potential mitigation strategies. These activities will include close coordination with the RISC as well as taking steps to create industry wide awareness.

Action Plan – OC 1

The OC will actively seek and recommend emergent operating issues, and help establish the priorities in coordination with the RISC while engaging with the appropriate parties to identify and develop the necessary mitigation processes or proposed solutions, such as revisions to standards or the development of Reliability Guidelines or other documents to inform the industry and eliminate reliability gaps.

The OC will review emergent issues at each standing committee meeting for status, progress and re-prioritization (as necessary) and assign to the appropriate sub-committee(s).

The OC will assess and inform the industry on the evolving reliability impacts due to changes in the performance, operation, or topology of the Interconnections.

The OC will continue to identify gaps, operating challenges, reliability impacts, and operating trends associated with generation and demand-side resource changes and develop proposed solutions.

The OC will continue to assess and inform the industry on the reliability impacts of natural gas/electric generation interdependences and provide recommendations where appropriate.

The OC will assess, evaluate, and inform the industry on the reliability impacts of fundamental changes to interconnected operations, such as changes to the footprints of reliability coordinators, balancing authorities, transmission operators, Interconnections, and High Voltage Direct Current (HVDC) ties, etc.

The OC will assess, inform, and where appropriate, provide solutions to the industry on the reliability impacts from possible high-impact, low-frequency events that could have unacceptable operational consequences on the BES.

Goal – OC 2 Promote EA Processes and utilize the results to improve the reliable operation of the BES. The OC will focus on event prevention by providing industry with information associated with good industry practices and emerging tools, technology and techniques. In addition, the OC will champion and continually enhance the EA program to rapidly develop and disseminate lessons learned. Finally, the OC will take steps to enhance stakeholder awareness concerning the application of lessons learned, good industry practices, and recommended actions.


The OC will review and approve the members of the Event Analysis Subcommittee (EAS) to ensure technical leadership and expertise is sufficient to allow the EAS to develop good industry practices and to identify emerging trends.

As a result of lessons learned and cause code trending, the EAS may recommend to the OC:



o Development and communication of reliability guidelines1

o Development and communication of reference documents2

o Development and communication of NERC Alerts

o Improvements to existing Reliability Standards

o New Reliability Standards

The EAS will present root causes and lessons learned at OC meetings with the objective of sharing information on industry improvement opportunities.

The EAS will leverage industry groups (such as the North American Transmission Forum and Generation Forum) in the development and communication of quality lessons learned.

The EAS, in coordination with the Personnel Subcommittee (PS), will recommend training and education as a result of lessons learned and emerging trends.

The EAS will periodically survey the Regional Entities to determine if lessons learned recommendations are being implemented and if not why. The EAS will report the survey results to the OC.

The EAS will develop a communication strategy in coordination with the appropriate parties to encourage the use of lessons learned and to inform the industry of current and past lessons learned and good industry practices.

Goal – OC 3 The OC will be proactive in the review of proposed Reliability Standards under development or revision. The practical application of new or revised Reliability Standards in enhancing reliability or mitigation of emerging risks will be assessed by the OC. The industry expertise of the OC will be leveraged to provide feedback with the intent of ensuring that standards are reasonable and provide reliability benefits. The OC will engage early in development processes to ensure feedback is provided at the appropriate stage of the process.


The OC will:

Engage the of the Standards Committee and the Standards Drafting Team Chairs to update the OC on the associated standards to allow the OC to provide early review, discussion and guidance on recommendations.

Recommend to Standards Committee revisions to standards or the retirement of existing standards as appropriate.

Encourage OC involvement in the informal standards development process.

Prepare responses to requests for standard interpretations.

Establish and maintain a method for active management of field tests associated with standards development, including the leadership of the field test (as necessary).

Participate in the periodic review of the effectiveness of existing Reliability Standards.

1 Proactively reach out to stakeholders through the OC guidelines outreach process (See “Action Plan – OC 5” below for details) 2 Proactively reach out to stakeholders through the OC guidelines outreach process (See “Action Plan – OC 5” below for details)



Goal – OC 4 Improve the depth of NERC reports to include operations perspectives. Key findings and recommendations within NERC reports may serve as the technical basis for NERC Reliability Standards, project prioritization, compliance improvement, assessments, and critical infrastructure protection, as well as a roadmap into the future. In addition, technical reports provide information on reliability impacts to governmental bodies which enhance their decision making capabilities. Therefore, the OC will be proactively engaged in the development of NERC reports. By providing early input into NERC, the OC can provide a valuable service to the industry, as well as support NERC in addressing its top priorities.


The OC will direct the Resources Subcommittee to coordinate with the NERC Performance Analysis Subcommittee to provide reports and information as needed.

The OC will direct the Operating Reliability Subcommittee to coordinate with the NERC Reliability Assessment Subcommittee to provide reports and information as needed.

The OC will provide input, review and endorse NERC’s annual State of Reliability report.

The OC will assure OC representation, and will collaborate, with the appropriate subgroups on issues such as:

Reliability metrics

Operational Security

Interconnection frequency response

Performance analysis

Essential Reliability Services

Other groups identified by current and emerging technologies, such as inverter-based resources

The OC will engage in the NERC Special Assessment Process by:

Providing feedback and recommendations on Special Assessment topics.

Providing feedback on Special Assessment Reports.

Assigning expert operations personnel, as needed, to assist in the development of Special Assessments.

Goal – OC 5 Improve the depth of the ongoing OC Activities. The OC provides the industry with, information associated with the effectiveness of the day-to-day reliability of the BES, review of the effectiveness of ongoing personnel training activities, and impacts of BES issues.


The OC will oversee and guide the PS in the development and update of the manual for continuing education.

Provide a process that assures high quality training for the BES personnel.

Oversee continual education training and provide recommendations for improvement



The OC will review, modify (as necessary), and approve sub-committee reports on the performance of the day-to-day reliability of the BES.

The OC will participate in, review and submit (if appropriate) reports to industry on impacts associated with the BES.

In order to enhance industry outreach and communication of reliability guidelines, reference documents and lessons learned, the OC process is as follows:

Single website location for all committee reliability guidelines and reference documents

Short overview of each of the reliability guidelines and reference document (similar to quick reference guide for LLs)

Formal rollout process for new and updated reliability guidelines and reference documents

Post links to single library location

Overview in the announcement of a reliability guideline and reference document

Communicate a clear purpose for any posting

Provide a contact for stakeholders to send comments/questions

Reliability guidelines will be grouped together based on focus area

Reference documents will be grouped together based on focus area

Lessons learned will be grouped together based on focus area

Webinars will be held for all new reliability guidelines and when updating a reliability guideline to discuss changes

Engage the Regional Entity by volunteering to present new reliability guideline and reference documents and updated guidelines and reference documents

Coordinate with forums and policymakers (governmental entities)

Identify reliability guidelines and reference documents that are under development and revision at the joint OC/PC/CIPC meetings

NERC Operating Manual

Lloyd LinkeOperating Committee MeetingSeptember 12, 2017


• Was the bible for the Operating Committee 628 pages

• History, map, procedures for standing committees, procedure for developing and approving standards, procedure for waivers, Control Area criteria, RC standard of conduct

• Contained all the policies Transferred to initial version zero standards

• Training Documents - 3

• Data - 3 Control area names, L10, Bias settings

• Reference Documents - 12

Operating Manual 2004


• Collection of documents 125 pages

• History Not updated since Oct 2003

• Procedures for Standing Committee – Board June 2004 Rules of Procedure

Charters

• RC Standard of Conduct – Oct 2000

• Training document – 1

• References documents -3

Operating Manual Today


• Training – 1 Area Interchange Error Survey Training Document

o Currently under review

• Reference – 3 Performance Standards Reference Document

o OC Approved revision June 2017

Interchange Reference Document

o OC retired June 2017

Electric System Restoration Reference Document

o OC retired December 2016

Documents


• Keep the manual? As is

Add all our reference document

• Archive it? Keep the documents still in the manual as normal OC reference documents

• Others????

• Discussion tomorrow morning

What do we do?


August 21, 2017 - Solar EclipseTim Reynolds

WECC Event Analysis & Situation Awareness Department

W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C O U N C I L

NERC EAS/OC/PC Meetings

Quebec City, Sep 11-14, 2017

August 21 Solar Eclipse Agenda

• Preparation/Coordination

• Eclipse path

• Observations/Impacts

• Next steps

2


Total Solar Eclipse3


*Source: Dean Spratt

WECC Entities Preparation• Studies started in Fall of 2016

– CAISO Analysis of the August 21, 2017

• Planning and Coordination Meeting– Biweekly Planning Calls– Day Before Event

• Periodic webinars– California Public Utilities Commission– Peak RC Round Table Discussion

• Coordination work done with third-parties

4


https://www.caiso.com/Documents/Briefing_SolarEclipse-ISOReport-May_2017.pdf

https://ia.cpuc.ca.gov/caleclipse/

https://www.peakrc.com/whatwedo/Outreach/Lists/Calendar/DispForm.aspx?ID=13

WECC Entities Preparation

• WECC BAs procured additional– Gas resources

– Use of fast acting hydro, thermal, and pump storage generation

– Regulating reserves

• Restricted Maintenance Orders

• Public appeal for energy conservation

5


Eclipse Impacts on Solar Energy6


Thermal Effect of the Eclipse7


Preparations vs Observations 8


Northern Region: Area Loading9


Max Solar Ramp Rate During Eclipse:

Ramp Down• 14 MW/min

Ramp Up • 15 MW/min

Southwest Region: Area Loading10





Southeastern Region: Area Loading11





Eastern Region: Area Loading12





Notable Differences During the Event

Increased Operating and Spinning reserves

13


Notable Changes in Path Flows

Operating Spinning

CAISO Typical Renewable14


CAISO Net Demand (i.e. Duck Curve)15


Net Load = Actual Load – (Solar + Wind Generation)

CAISO Renewable Generation16


CAISO Net Demand During Solar Event17


Net Load = Actual Load – (Solar + Wind Generation)

Current and Future Activities• Post Analysis Reports

– California ISO Report• Include ISO’s planning, execution, and results of managing the eclipse• Should be completed late September

– California News Release

– Peak RC and NREL Report• https://openpv.nrel.gov/• Calculated number for distribution PV by BA

– Peak RC’s 1 min state-estimation snap shots during eclipse– Peak RC’s data historian data

• Report will be public

18


http://www.caiso.com/Documents/CaliforniaISOSuccessfullyWeatheredSolarOutputDropDuringEclipse.pdf

https://openpv.nrel.gov/

Question?

email: [email protected]

19


mailto:[email protected]

Duke Energy’s Solar Eclipse Experience

Brett Koelsch, Duke Energy

[email protected]

NERC EAS/OC/PC Meetings

Quebec City, Sep 11-13, 2017

Agenda

Pre-event expectations and preparations

Solar generation in Duke Energy service territories

Carolinas Solar generation output during eclipse event

Load during eclipse event

Balancing resources and demand during event

Objective & Agenda

2

Share Duke Energy’s August 21, 2017 Solar Eclipse operating

experience with managing solar generation output, load changes,

and balancing resources and demand through the eclipse eventObjective

Connected Solar Generation in Duke Energy Service Territories

RegionConnected Solar (Nameplate MW)

DEC (Carolinas West) 693

Transmission 228

Distribution 465

DEF (Florida) 64

DEK; DEI; DEO

(Kentucky, Indiana, Ohio) 66

DEP (Carolinas East) 1836

Transmission 525

Distribution 1154

Wholesale 157

Duke Energy Total 2659

3

Preparations for the Eclipse – Obscuration and Weather Forecasts

4

Weather forecasts for DEC and DEP BA/TOP

Footprints on 8/20 were for mostly sunny skies

and high temps in the lower 90’s on 8/21.

Charlotte expected 98% obscuration;

Raleigh expected 93% obscuration.

Solar Output Forecasts and Planning Objectives on 08/20/2017

5

3 89

343

692

999

11881249

884

83

572

841

506

189

32

0

200

400

600

800

1000

1200

1400

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

8/20 Forecast for DEP BA Solar Output on 08/21 (combined Transmission and

Distribution connected Solar)

Base Solar [MW] Eclipse Solar [MW]

1. Preserve System Reliability – Ensure Capacitor Banks are available

Coordinate closely with Distribution Control Center

Monitor RTCA closely

Maintain extra spinning reserves – primarily on gas CTs

Develop, communicate, and implement solar curtailment plans

Coordinate Unit Commitment /Fuel planning

Communications planning – anticipated high cell phone usage from live streaming of eclipse – test backup communications with Plants and field personnel.

Consider high vehicle traffic in service territory may slow response times to some areas.

Anticipated A/C load lagging temperature drop, lighting loads.

2. Ensure Compliance with NERC Standards BAL-001-2 – Maintain margin with BAAL limits

BAL-002-1 – Ensure ramping doesn’t impede ability to recover with DCS event

3. Operate Safely & Economically

Actual Solar Generation Output During Eclipse (DEC and DEP Bas)

6

Actual Solar Output Changes

7

Duke Energy Load and Temperature During Eclipse

8

Duke Energy Load and Temperature During Eclipse

9

Balancing Resources and Demand During Eclipse

10

Lessons Learned from Eclipse Experience

Influences on Customer Demand – Reduction in demand was not predicted.

Solar Output Forecast – With day ahead forecast more certain, solar forecast was fairly accurate

Solar Generation Information – Definitely a benefit to have visibility of solar through telemetry.

Flexible Reserves - Flexibility in on-line reserves was used to manage the expected significant change in solar output and the unexpected change in customer demand

Non-solar Generation - Having a flexible plan well communicated to the non-solar generation fleet was beneficial.

Prior Communication with Utility Commissions, Media, and Internal to the Companies was beneficial.

11

12

BAL-003 SAR Motion

Operating Committee Meeting

September 13, 2017


• Motion made by Jerry Rust: Recommend that the SC post the SAR for comments and recommend a

single drafting team to address the existing RS SAR on BAL-003 as well as this SAR

OC agrees that there is sufficient technical justification presented to move forward with this SAR

Encourage the SC to move the SAR forward for standard development

Motion


FRSG SAR Submittal

BAL-003-1.1

September 2017


Topics

• History of the FRSG SAR Submittal Process

• Technical Justification Topics Real-Time Reliability

Event Selection and Measurement

Obligation for Applicable Entities

Assumptions behind the Original Standard

• Goal of a Reliability Standard

• Interconnection Differences

• Commitment to Drafting Team

• Proposed OC motion

History of the FRSG SAR

Submittal Process


History (Current FRSG Membership)

• Current membership of the FRSG includes: Canadian Independent System Operator

Federal and Provincial Entities

Public, City, Municipal and Irrigation Districts

Investor Owned Utilities

Generation only BAAs

o Includes Generation-Only BAAs (both wind and thermal)

Entities that are fundamentally hydro only, thermal only and combination of all generation types.

Includes small (under 1000 MW) , medium (1000– 5000 MW) and large (>5000 MW) BAAs within the Western Interconnection (WI)


• Alberta Electric System Operator

• Avista Corporation

• Balancing Authority of Northern California

• Bonneville Power Administration

• PUD No. 1 of Chelan County, WA

• PUD No. 1 of Douglas County, WA

• PUD No.2 of Grant County, WA

• Gridforce Energy Management

• Idaho Power Company

• NaturEner Power Watch, LLC (GWA)

History (Current FRSG Membership)

• NaturEner Wind Watch, LLC

• Nevada Power Company

• NorthWestern Energy

• PacifiCorp (2 BAAs)

• Portland General Electric Company

• Puget Sound Energy, Inc.

• Tacoma Power

• Turlock Irrigation District

• Western Area Power Administration - Upper Great Plains


History

• The FRSG does NOT include any economic or market making functions. The FRSG focuses solely on the reliability impact of Frequency Response and the ability to comply with the BAL-003-1 Standard


History

• The FRSG represents 20 of the 38 BAAs in the Western Interconnection (WI) The FRSG’s FRO is -370 MW/.10 Hz.

Total WI IFRO currently -858 MW/.10 Hz

The FRSG is responsible for ~43% of the WI Frequency Responsive Requirements


History

• When measured as a group the current FRSG has NEVER failed to meet the combined groups FRO for a single select frequency event for events selected for prior years evaluation (2015-current quarter events).

• For the most recent compliance monitoring period the FRSG provided on AVERAGE 87.95% of the WI IFRO and supplied 80.16% of the WI IFRO for its’ median event.


History

• The Northwest Power Pool began working on formation of a “FRSG” beginning in August of 2015.

• Monthly (or more frequent) meetings of technical representatives of its’ members continued throughout the remainder of 2015 and through July 2016 on the formation of the FRSG

• Twenty BAAs entered into the formation of the FRSG for compliance year beginning in December 2016


History

• Through this joint effort the historical Frequency Response performance of the 20 BAAs was analyzed.

• This nearly two year effort of reviewing entities performance across a region has illuminated many issues regarding the current standard’s requirements.


History

• The FRSG meets regularly throughout the operating year to review the participant BAAs’ generator frequency response performance with regard to BAL-003 requirements, both individually and collectively.

• The FRSG continues to develop and refine future year(s) operating rules.

• The FRSG identifies and creates additional monitoring tools for documenting performance (Form 3) and develops real-time situational awareness of frequency responsive resources for system operators


History

• From the first meeting on the formation of the FRSG, work began on identifying issues with the current BAL-003 Standard; this resulted in the FRSG creating a SAR to address the issues identified by the group.

• Members of the FRSG have discovered and reported to NERC a multitude of issues with the FRS Forms 1 and 2 through this extensive review process.


History

• On February 17, 2017 the FRSG submitted its BAL-003 SAR to NERC

• On May 24, 2017, the FRSG received a request from the Standards Committee (SC) to submit a technical justification for the FRSG’s BAL-003 SAR

• On June 28, 2017 the FRSG submitted a technical justification paper to the SC supporting the need for modifications to the existing BAL-003-1

• On July 19, 2017 the SC deferred to NERC OC for action on this SAR

Technical Justification

Topics


Technical Justification Topics

• Real-Time Reliability

• Event Selection and Measurement

• Obligation for Registered Entities

• Assumptions Behind the Current Standard


Real-Time Reliability

• BAL-003 as currently configured does not require response to any single event Under the current standard, we could experience UFLS on 12 of 25 events

and no violation of the standard occurs.

Measurement of historical events does not ensure real-time operations has adequate frequency response

• IFRO is determined through the use of two-year old information and may not accurately represent the frequency responsive characteristics for the year in which it is applied.


Real-Time Reliability

• Also, frequency response is necessary within the first 20 seconds to arrest and stabilize rapid frequency decline The 20-52 second measurement period incentivizes entities to tune

facilities for maximum compliance and not maximum reliability.

With the increased insertion of inverter based resources in the WI we are seeing a dramatically “faster” Rate Of Change Of Frequency during resource losses


• Current BAL-003 is driven by historical analysis of selected events and the selection criteria does not always measure frequency response. Performance metrics should reflect dead bands, beginning frequency, size

and type of events, an adequate number of events, and most importantly time of measurement

• Frequency response of synchronous generators can only be accurately measured during machine movement outside of programmed deadbands.

Event Selection


• The current standard uses Net Interchange Actual (NIA) to measure compliance Changes in load, intentional changes in generation dispatch, changes in

purchases, pseudo-tie values, changes in transmission flows and losses, and others all mask the actual frequency response of the BAA.

Statistical analysis can support measurement only when all inputs can be determined to isolate the value being measured for compliance.

NIA has too many variables, all changing at the same time, to be treated as the sole measure of frequency response.

Dynamic schedules are not included in the measurement, even though they may have a response component.

• Frequency response is not linear thus distorting the FRM measure, especially for events with an A to B measure less than 0.1 Hz

Measurement

and others all mask the actual frequency response of the BAand others all mask the actual frequency response of the BA


• Only Balancing Authority Areas or Frequency Response Sharing Groups are applicable entities in the existing standard.

Although all frequency responsive resources reside within a BAA, BAAs do not have any ability to hold resources accountable for frequency responsive performance in the current standard or in provisions of a FERC Pro Forma Tariff

Many potential future sources of Frequency Response (DERs) do not fall within the authority of NERC.

When a new resource or BAA is added to or removed from the Interconnection, the determination of IFRO and its allocation to the BAAs is not addressed in the Standard.

Obligation for Registered Entities


Assumptions Behind Current Standard

• BAL-003 appears to assume that all BAAs have the same composition and operate in the same manner. Of the 38 BAAs in the WI there is a wide variation of operation 100% generation only

100%wind only

100% hydro base

100% thermal base

“Conventional” Balancing Area mix

BAAs that have NO resources on line for a significant amount of the year


Assumptions Behind Current Standard

• The standard does not recognize the changes associated with inverter based resources and impacts associated with behind-the-meter generation. The allocation formula rewards a BAA with behind-the-meter generation

and places the burden of frequency response on the remaining BAAs

Goal of a Reliability

Standard


Goal

• NERC Reliability Standards define the reliability requirements for planning and operating the North American bulk power system and are developed using a results-based approach that focuses on performance, risk management, and entity capabilities.


BAL-003-1.1 Purpose

• To require sufficient Frequency Response from the Balancing Authority (BA) to maintain Interconnection Frequency within predefined bounds by arresting frequency deviations and supporting frequency until the frequency is restored to its scheduled value.

• To provide consistent methods for measuring Frequency Response and determining the Frequency Bias Setting.

Western Interconnection

Differences


Regional Differences

• The four interconnections are VASTLY different Two of the four are SINGLE BA interconnections

o Hydro Quebec

o Texas Interconnection

Texas Interconnection operates a single market and has a regional standard for frequency response

o BAL-001-TRE-1 has requirements for governor response and tuning requirements.

o Allowances for units not online during events

o Deadband and droop settings based upon type of resource and technical requirements of equipment





Table 3: BAL-003-1.1 Event Selection Criteria

Interconnection fAC (mHz) and Point C frequency (Hz)

Eastern 40 <59.96 or >60.04

Western 70 <59.95 or >60.05

ERCOT 80 <59.90 or >60.10

Québec 300 <59.85 or >60.15

Commitment to Standard

Drafting Team


• The following Northwest entities and organizations have committed to participate in a Standard Drafting Team: Avista

Bonneville Power Administration

Northwestern Energy

Northwest Power Pool (representing 20 BAAs)

PacifiCorp

Puget Sound Energy

Standard Drafting Team

OC Motion


Motion

The OC Moves to approve the Technical Justification of the SAR associated with BAL-003-1.1. Further, it recommends the Standards Committee post the SAR for comment and the establishment of a drafting team.


BAL-002-2 DCS Data

Collection

Tim Reynolds, NERC RS Vice Chair

NERC Operating Committee

Sept 12, 2017


• BAL-002-2 comes into effect 1/1/2018

RSGs/BAs no longer required to submit quarterly data to their respective regions and RS representatives

• Still need data collected for

NERC RS review of control performances

FERC Order 835

NERC PC approved M6 and M7 metrics for NERC State of Reliability Report

• Reserve Sharing Work Group (RSG) developed a form to collect data from RSGs and individual BAs not participate in a RSG

• Data will be kept confidential according to NERC Rules of Procedures

• The DCS Event Data collection process will begin January 1, 2018

• The form will be requested to be completed within 15 days upon the end of each calendar quarter.

• The DCS Form will be maintained on the NERC SharePoint BAS site.

Background Information


Screen Shot of Form


The RS requests:

1. The OC to approve collection of DCS Event Data related to BAL-002-2, with the provision this data will be used for reliability purposes.

2. The RS is requesting the OC chair to issue a letter to the BAs/RSGs to submit the completed a DCS Event Form to the BAS site.

- Similar to the request done for the CPS1/BAAL data collection.

- Letter will contain instructions on how to use the BAS site.

NERC RS Request
