Integration of Variable Generation Task Force Highlights and...Integration of Variable Generation...

Integration of Variable Generation Task ForceSummary and Recommendations of 12 Tasks Report

Noha Abdel-Karim, Senior Engineer, NERCPlanning Committee Meeting June 9-10, 2015

RELIABILITY | ACCOUNTABILITY2

Overview: The final report recognizes the accomplishments of the 12 IVGTF efforts

that address broader and detailed aspects of integration large amounts of variable generation.

The IVGTF leadership summarized and refreshed each of the task’s recommendations and conclusions.

Objectives: Evaluate the effects of large-scale integration of VG and identify the long-

term reliability considerations needed to ensure the reliability of the BPS Determine the status of these recommendations by identifying a transition

plan next steps for NERC – Complete

Summary Report - Update


• Transition plan is complete. Task 1-3 on interconnection requirements since last PC/OC March

meetings Updated transition plan to include “NERC External Coordination Effort”

category - IEEE 1547 recommendations (Tasks 1-3 & 1-7)

• Coordination and collaboration effort resulted in reviewing recommendations form the 12 tasks reports and finalizing actionable transitions IVGTF Standards NERC-RAPA Staff SAMS ERSTF PC and OC

IVGTF Transition Plan Update


Appendix I –IVGTF Transition Plan Standards Review and/or Standard Authorization Request (SAR) Enhancements to Modeling Definition – Revisions or Addition By NERC Operating – Technical Guidelines Planning – Technical Guidelines Research and Development NERC Training and Education NERC Reliability Assessments Data Collection Essential Reliability Services Task Force (ERSTF) NERC Staff/External Coordination Activity No Action: (i.e., recommendation is out of scope and is not applicable,

such as due to market or commercial action improvements, or has been addressed by different projects).

IVGTF Transition Categories


Standard Models for Variable Generation (Task 1-1)4%

Methods to Model and Calculate Capacity Contributions of Variable Generation for Resource Adequacy Planning (Task 1-2)7%

Interconnection Requirements for Variable Generation (Task 1-3)32%

Flexibility Requirements and Metrics for Variable Generation: Implications for Planning Studies (Task 1-4)6%

Potential Reliability Impacts of Emerging Flexible Resources (Task 1-5)6%

Probabilistic Methods (Task 1-6)6%

Performance of Distributed Energy Resources During and After System Disturbance (Task 1-7)2%

Potential Bulk System Reliability Impacts of Distributed Resources (Task 1-8)2%

Variable Generation Power Forecasting for Operations (Task 2-1)13%

Reliability Considerations for BA Communications with Increased Variable Generation (Task 2-2)5%

Ancillary Services and Balancing Authority Area Solutions to Integrating Variable Generation (Task 2-3)5%

Operating Practices Procedures and Tools (Task 2-4)12%

Break Down By IVGTF Task Report


0

5

10

15

20

25

30

35

40

45

50

NO

. OF

RECO

MM

ENDA

TIO

NS

Break Down By Transition Category


Standards Interconnection Requirements Reactive Power & Voltage Control Requirements Active Power Control Capabilities Variable Generation Forecasting Requirements

Planning –Technical guidelines Interconnection Requirements Resource Adequacy Essential Reliability Services Generation and Transmission Planning Probabilistic methods

Operating –Technical guidelines Active Power Control Capabilities Technical Developments – DER & DR Flexibility Requirements VG Forecasting Requirements Essential Reliability Services Interconnection Requirements

Main Transition Grouping – Next Steps

Task 1-1: Standard Models for Variable GenerationTask 1-3: Interconnection requirementsTask 2-4” Operating Practices Procedures and Tools

Task 1-1: Standard Models for VGTask 1-2: Methods to Model and Calculate Capacity Contributions Task 1-3: Interconnection requirementsTask 1-4: Flexibility Requirements Task 1-5: Potential Reliability Impacts of Emerging Flexible ResourcesTask 1-6: Probabilistic MethodsTask 1-8: Potential Bulk System Reliability Impacts of Distributed Resources

Task 1-3: Interconnection requirementsTask 1-5: Potential Reliability Impacts of Emerging Flexible ResourcesTask 2-1:Variable Generation Power Forecasting for OperationsTask 2-3: Ancillary Services and Balancing Authority Area Solutions to Integrating Variable GenerationTask 2-4” Operating Practices Procedures and Tools


NERC Staff Recommendations

• NERC Staff will delegate this continuing monitoring effort to NERC reliability assessments and special assessment reports, Standards

• NERC staff recommends transitioning follow-on work to the NERC Reliability Assessments work plan, NERC working groups, task force(s), and Standards Department

• NERC staff will continue monitor the progress of the IVGTF recommendations and coordinate technical discussions between the OC/PC and IVGTF follow-up groups


Motion Request

Disband the IVGTF

Probabilistic AssessmentImprovement Plan

Noha Abdel-Karim, Senior Engineer for Reliability AssessmentPlanning Committee MeetingJune 9-10, 2015


• Calculate a complete and non-overlapping set of probabilistic reliability metrics across the NERC footprint.

• Perform a resource adequacy assessment covering all hours (compared to the peak demand hour observed for each season in the LTRA).

• Provide probabilistic reliability metrics for each NERC Assessment Area and convey a clear understanding of the reserve margin implications.

• Compare results over time and between studies.

ProbA Objectives


• Examine the availability of non-Firm capacity transfers between Assessment Areas.

• Provide a composite generation and transmission assessment (resource adequacy), which considers the ability of load to receive power supplied by aggregate resources.

• Calculate probabilistic uncertainty measures under a scenario with load interrupted to maintain all operating reserves.

ProbA Objectives


• Scenario analysis: has a significant impact on LOLH and EUE measures in most Assessment Areas: Findings encourage further probabilistic development to assess overall BPS

reliability, primarily in the context of resource adequacy planning, but also for operations.

• MISO tight PRM at increasing LOL Statistics Planning Reserve Margin: approaching the Reference Margin Level with

increasing LOL statistics. Modeling Approach: MISO relied on prospective instead of anticipated

resources in its probabilistic modeling approach.

• BPS Transformational Changes: in resources and load dynamic behavior strain essential reliability services. The continued application of probabilistic approaches in NERC assessments

will help planners and policy makers better understand the changing dynamics of the BPS.

Key findings & Recommendation Review


Reassess the ProbA Study Effort• NERC identified several considerations and lessons learned that

should be evaluated before proceeding with additional probabilistic assessments.

The Planning Committee should consider:• Reviving the Generation and Transmission Reliability Planning

Models Task Force (GTRPMTF).• Centralizing the approach for probabilistic assessment to gain

consistency in modeling and modeling assumptions.• Increasing value of the transmission parameters required for the

probabilistic assessment.• Aligning an approach for scenario development with high-risk

emerging reliability issues.

Recommendations to PC


In an effort to improve NERC’s continuing probabilistic assessment evaluations, the PAIG will support the identification of improvement opportunities for NERC’s Long-Term Reliability Assessment. • Apply more rigorous treatment of the uncertainties impacting

the reliability of the operation and planning of the BPS.• Determine the impact of the transformational shift in BPS

resource adequacy on reserve margins by assessing Short term uncertainties inside timeframes of one year – Seasonal

Resource Adequacy Assessment. Long term uncertainties over a multi-year period – Annual Probabilistic

Resource Adequacy Assessment.

Probabilistic Assessment Improvement Group (PAIG)


Proposed Approaches:• Improve current probabilistic assessment reports Introducing additional metrics (i.e., LOLE, ALLR Annual Load Loss Risk) and Applying additional scenario analyses addressing areas specific issues. Modeling consistencies with LTRA.

• NERC Centralized Regional Approach Evaluate resource adequacy in a probabilistic fashion using a common

assessment method – NERC Centralized Regional Approach in developing a consistent BPS probabilistic resource adequacy model

Identify uncertainties, trends and report results using NERC probabilistic analysis.

Improvement Plan


The PAIG will develop a multi-year work plan to support needed enhancements:• The group will evaluate the assessments performed to date (two

complete assessments in 2012 and 2014, and one pilot in 2010) and determine potential solutions for improvements. Improvements should be identified in four areas: Process and Coordination, Data Coordination and Needs, Assumptions, Criteria, and Requirements, and Modeling Software Requirements.

• Develop recommendations for improvements• Develop a draft report should be completed by the September

PC Meeting.

PAIG Activities


Request PC guidance• PAIG workplan and activities

Representatives• From the now-disbanded GTRPMTF• Open representation facilitated by NERC Staff. Suggested

participants are: Members of the Planning Committee, and Members from the Reliability Assessment Subcommittee (RAS) Regional Entity participation

PAIG - Support

Essential Reliability Services Task Force Status UpdateBrian Evans-Mongeon, ERSTF Co-Chair, Pooja Shah, NERC StaffPlanning Committee MeetingJune 9-10, 2015


• Measure 7 – Reactive Capability of the System - Pilot conducted for this measure which was endorsed by OC and PC in March 2015

• A small subgroup formed to evaluate BPS related concerns with Distributed Energy Resources, in coordination with IEEE 1547 group - 6 ERSTF members recruited to participate in IEEE 1547 group

• Draft Framework Report 2 – sent to OC and PC for review

• ERSTF reviewed and commented on IVGTF recommendations –section related to IVGTF included in Framework Report 2

ERSTF Recent Activities


• Measures Finalized in Framework Report 2 Measure 1- Synchronous Inertial trend (Interconnection)

Measure 2 – Initial Frequency Deviation following largest contingency

Measure 3 - Synchronous Inertial trend (Balancing Area)

Measure 4 – Frequency Response

Measure 6 – Net Load Ramping Variability

Measure 7 – System Reactive Capability

• Under development Measure 10 – Voltage: Short Circuit System Strength (in place of Measure 8 which was

eliminated after review and analysis)

• Industry best practice recommendation Measure 5 – Real time inertial model

Measure 9 – Voltage-System Performance

ERSTF Status


Frequency Subgroup Measures Update • Measure 4: Frequency Response The subgroup has evaluated this measure further using the Eastern and

Western Interconnection, and ERCOT’s Frequency Response data. No additional data is required beyond the data already submitted for the

annual frequency response analysis. The subgroup will evaluate the results for this measure for next ERSTF

meeting Recommending 4 trending measureso A-B : Effectiveness of primary responseo A-C : Nadir-based frequency responseo C-B : Speed of primary responseo C-C’ : Governor response withdrawalo Time based measures to capture speed of primary response and withdrawal

ERSTF Measures Frequency Subgroup


Load and Resource Subgroup Measure Update• Measure 6: Net Load Ramping variability Out of 9 entities that submitted data for this measure, only CAISO is

currently experiencing challenges with ramping variabilityo CAISO currently has about 10,000 MW of transmission as well as distribution connected

solar resources.o Expected to increase by an additional 4,000 MW to 6,000 MW by the end of 2018

Appears to be a good directional measure for forecasting ramping needs and challenges.

Current framework can be used to determine each entity’s future needs for ramping, as well as challenges with load forecasting due to non-dispatchable and non-visible DER

Recommendation: BA’s should trend these quantities to evaluate/identify ramping needs and challenges as the resource mix evolves.

ERSTF Measures Load and Resource Balance Subgroup


Voltage Support Subgroup Measures Update• Measure 7: Reactive Capability of the System Data request sent to 9 entities for evaluating Entities submitted historical,

present and forecasted data. The results were evaluated by sub-group The preliminary data did not show a trend in decline of system reactive

capability, however it appears to be a valuable measure for BAs to monitor. Recommendation: BAs should continue to trend these quantities on an

ongoing basis preferably by sub-areas to look for new trends and to promote the optimization of dynamic, static and reactive load. The measures should be reported based on requirements to be specified by the Performance Analysis Subcommittee.

Update on ERSTF MeasuresVoltage Support Subgroup


• Measure 10: Measure and evaluate System Strength through Short Circuit Ratio (SCR) – The subgroup discussed the need for planning coordinators to conduct a high level short circuit strength screening in traditionally weak areas of their system or in areas with a high percentage of installed or planned inverter based resources. The PC’s should consider additional more detailed studies to identify potential control system interactions using techniques identified in the ERCOT and GE SCR study approaches.

ERSTF Measures Voltage Support Subgroup


• Next steps for the task force: Continue to develop Framework Measures Report Version 2 and capture

latest Task Force analysis (including all measures) Continue developing draft Final Report (June 2015) on Measures and

Methodology Coordinate with NERC External Affairs on developing a simplified

document for ERSTF work Working Meeting in August – MISO

Next Steps


•Next steps for the task force (cont.): September OC/PC – Present Preliminary Findings and Report for

comments

December OC/PC – Present Final Findings and Report

December 12-29 – Update final report from comments

December 31, 2015 – Issue Final Report

February 2016 – NERC Board of Trustees Meeting – Acceptance and Approval of the Final Report

Next Steps

2015 LTRA Emerging IssuesPlanning Committee Input

Amir NajafzadehPlanning Committee Meeting June 9-10 , 2015


Overview

• Past Long-Term Reliability Assessment Emerging Issues• Previous Input and Recommendations• Additional LTRA Narrative Questions

2 Region specific questions

• Phasor Measurement Units Smart Grid Application – Operational Real-time, Planning and Offline

• Request for Input from the Planning Committee


2014 Long-Term Reliability Issues

2014 LTRA Key Findings• Reserve margins in several Assessment Areas are trending

downward, despite low load growth• Environmental regulations create uncertainty • A changing resource mix requires new approaches for assessing

reliability• Other Reliability Issues

Load forecasting uncertainties System behavior impacts due to changing system resource mix and

load compositions Transmission siting, permitting, and other right-of-way issues Workforce transformation and aging infrastructure


2013 Long-Term Reliability Issues

2013 LTRA Key Findings• Reserve margins in several Assessment Areas• Continued integration of variable generation• Fossil-fired retirements and coordination of outages for environmental

control retrofits• Increased dependence on natural gas for electric power• Increased use of demand-side management• Nuclear generation retirements and/or long-term outages• Other Reliability Issues

Load forecasting uncertainties Global supply chains and fuel reliability Region/Interconnection wide modeling Workforce transformation and aging infrastructure Smart grid


Previous RecommendationsMRC, PC, and RAS Input

Select recommendations from the previous surveys:

• The need for more analysis and scenarios in assessments Evaluate the implications of nuclear generation retirement on reliability More granular analysis on distributed and variable resources Common-mode forced outages of gas-fired capacity Need for flexibility and essential reliability services

• Continued heightened awareness Initiate focused assessment Expand coordination with study groups


Identification of Issues

LTRA forms the basis for NERC reference case incorporating known policy and regulation changes expected

Economic growth, weather patterns and system equipment behavior Other challenges such as emerging regulatory and legislative mandates

Prioritization of NERC-wide and Regional Issues


Questions Format

Focus on risks to long-term BPS reliability

• What are the reliability implications of the subject• What are the long-term emerging concerns • What are the emerging issues with trends seen in planning and

operations today• What are the mitigation strategies planned to address these

issues


2015 LTRA Schedule

Date DeliverableJanuary 20 Data and Narrative Request sent to Regional Executives and RASFebruary 10 RADWG Meeting to Review Data Forms and InstructionsJune 12 was May 29 Initial Data due to NERCJune 12 was May 29 Initial Narrative Due to NERC and RAS-PlusJune 26 new NERC to send bullet-point front section topics and ask for input from the reps June 26 was June 12 Peer Reviewer Comments Due to RASJuly 10 was June 26 Narratives with All Comments and ResponsesJuly 21-22 RAS face-to-face Meeting at HQTE, Montreal July 31 Final Narratives and Data Due to NERCAugust 21 Draft Posted by NERC to RAS Shared DriveSeptember 4 Report Sent to RAS, PC, OC, and MRC for ReviewSeptember 15-16 Report Findings Presented to the PCOctober 2 PC Accepts Assessment Process FollowedOctober 5 NERC Editor ReviewOctober 19 NERC Executive Management ReviewNovember 6 Report Sent to NERC Board of Trustees for ReviewNovember 20 NERC Board of Trustees Vote to Approve ReportDecember 1 Target Release

Reliability Assessment SubcommitteeStatus Update

Layne Brown, RAS ChairPlanning Committee Meeting June 9-10 , 2015


2014 Probabilistic Assessment• Released in March 2015

2015 Summer Reliability Assessment• Released in May 2015

2015 Long-Term Reliability Assessment• Target release in December 2015

2015-2016 Winter Reliability Assessment• Target release in November 2015

Reliability Assessment Subcommittee2015 RAS Work Plan

2015 Assessments


Peer Review Process Enhancements2015 SRA Process Update

2015 Summer Assessment Peer Review Process Update• Assessment Areas addressed comments prior to the peer-review meeting The responses to questions and comments were more thorough and complete

• Overview of the assessment methodology and assessment procedures were provided by almost all of the Assessment Area representatives Enhanced peer reviewer understanding of the assessment area Review of regional planning and operational issues for the upcoming summer

season• Greater involvement from Assessment Area representatives to respond to

questions as well as explaining the methods and assumptions for the assessments

• Overall a positive enhancement in the process and more discussion around responding to the narrative questions


2015 Summer Assessment

• The Assessment Areas (WECC and New England) were closely involved in development of the key findings on: Extreme-case scenario analysis shows the California drought is not expected to

impact BPS reliability. Ongoing natural gas infrastructure expansion and outages in New England are not

expected to impact summer peak reliability.

• The 2015SRA introduced a pilot analysis that focuses on operational risks to the BPS utilizing the data collected for the assessment as well as GADS data.

• RAS will continue supporting and refining this effort for the 2015-2016 Winter Reliability Assessment


Performance Evaluation Metrics

Assessment Metric Parameter Measures• In order to increase Regional oversight on the Assessment

quality and process, addressing timing challenges and greater focus on assessment approaches, methods and assumptions; NERC and the Assessment Area representatives will evaluate performances based on parameters such as: Completeness, Timeliness, Accuracy, Responsiveness, etc.

• An evaluation questionnaire will be provided for evaluation of the Regional and Assessment Area performances after the RAS’ LTRA peer review meeting.


2015 LTRA Assessment Development

NERC narrative and data question sheets were sent to Regional executives well in advance in preparation for future MOD-31 data collection requirements.

Important dates: Initial data and narratives are due to RAS on June 12th 2015. Similar to the Summer 2015 Assessment peer review process;

incorporated and addressed comments are due to the RAS on July 10th 2015.

Peer Review meeting on July 21-22 2015.

July 21-22 2015 face-to-face meeting additional expectations: Assessment Areas will provide any regional emerging issues and trends in

their areas for the long-term assessment period. NERC will discuss the front section outline of the report and discuss with

the RAS


2015 LTRA Schedule

Date DeliverableJanuary 20 Data and Narrative Request sent to Regional Executives and RASFebruary 10 RADWG Meeting to Review Data Forms and InstructionsJune 12 was May 29 Initial Data due to NERCJune 12 was May 29 Initial Narrative Due to NERC and RAS-PlusJune 26 new NERC to send bullet-point front section topics and ask for input from the reps June 26 was June 12 Peer Reviewer Comments Due to RASJuly 10 was June 26 Narratives with All Comments and ResponsesJuly 21-22 RAS face-to-face Meeting at HQTE, Montreal July 31 Final Narratives and Data Due to NERCAugust 21 Draft Posted by NERC to RAS Shared DriveSeptember 4 Report Sent to RAS, PC, OC, and MRC for ReviewSeptember 15-16 Report Findings Presented to the PCOctober 2 PC Accepts Assessment Process FollowedOctober 5 NERC Editor ReviewOctober 19 NERC Executive Management ReviewNovember 6 Report Sent to NERC Board of Trustees for ReviewNovember 20 NERC Board of Trustees Vote to Approve ReportDecember 1 Target Release

2015 Summer Reliability AssessmentPilot Operational Risk AnalysisPooja Shah, NERC StaffPlanning Committee MeetingJune 9-10, 2015


• Assess extreme load scenario with typical and extreme generation outages – this determines whether the reserve capacity is adequate for each scenario

• This assessment used Generating Availability Data Systems data for scheduled and forced outages for summer months (June –Sep) for years 2011-2013

• 2015 Summer Reliability Assessment (SRA) data request included request for extreme load forecast (e.g. 90/10 forecast) in addition to normal load forecast for the summer

• Some Regions and Assessment Areas provided the values for forced outages for this pilot

Operational Risk AnalysisPilot for the 2015 SRA


• The analysis results helped show and compare the normal and severe case scenario for operational planning

• Overall most areas available resources covered their projected severe demand cases adequately

• In PJM, their severe demand forecast coupled with max forced outages projected operational inflexibility – which could be mitigated with Demand Response tools for example.

• More information available in the 2015 SRA

Operational Risk AnalysisResults


Analysis Process

3,248 3,248

34,738

32,443

1,124

1,124

41,222

37,868

5,425 3,131

106


Operational challenges for both normal and severe demand scenarios

2015 SRA Scenario Risk AnalysisMISO



2015 SRA Scenario Risk AnalysisPJM



2015 SRA Scenario Risk AnalysisISO-NE



2015 SRA Scenario Risk AnalysisERCOT


• NERC plans to continue this analysis for the seasonal assessments

• Methodology to collect forced generator outages will remain similar to the SRA process

• NERC team is looking for feedback on the analysis and input for future assessments – in terms of operational risk analysis

Looking for Input

Short-Term Reliability AssessmentProposal for PC Input

Planning Committee MeetingJune 9-10, 2015

Elliott NethercuttNERC Staff


STRA Overview• Release: annual release in late-April (replaces NERC’s seasonal assessments)• Period of Assessment: examines 12 or 18 month period (June – May or June - Aug)• Data: collected in March; update tollgates: September, December, May • Scope/Format: report format (30-40 pages); identifies both operational and planning

issues; highlights Regional and NERC-wide reliability & operational challenges• Analysis: reserve margins, operational risk assessment, shoulder periods, seasonal

resource and transmission adequacy• Report Development: NERC staff coordinating with the Operating Reliability

Subcommittee (ORS) in developing the report; Report review/acceptance of process from the Operating Committee (OC)

• Special Assessments: if additional upcoming issues/challenges are identified, NERC staff will release topic-specific assessments (1-3 page reports to be posted on NERC’s website). If necessary, NERC staff will coordinate with appropriate stakeholder groups/subcommittees to develop and collect additional data and information.

Short-Term Reliability Assessment Proposal


Short-Term Reliability AssessmentProposal

Report Attribute Current Seasonal Assessments Proposed STRA

Period of Assessment Summer: June-SeptemberWinter: December-February 12/18 Month

Data Collection Summer: early-AprilWinter: mid-October Mid-March

Development Reliability Assessment Subcommittee(RAS)

Operating Reliability Subcommittee(ORS)

Review / Acceptance Planning Committee (PC) Operating Committee (OC)


ORS Transition Plan for the STRA2015• June – August: NERC staff, in coordination with ORS, to draft update ORS

charter/scope to include STRA• August – September: ORS to review 2015 SRA and provide input for 2015-16 WRA• September: OC/PC approval of updated RAS and ORS charters• September – October: ORS to develop draft STRA data/narrative request• October: OC and ERO-RAPA to review and provide input• November: ORS to finalize data/narrative request• December: OC to review and approve data/narrative request; NERC to send to

Regions/ORS2016• January – March: Regional data collection• March – April: Data due to NERC; ORS peer review• Late-April: Target Release

Short-Term Reliability Assessment Proposal


STRA/LTRAProposed Schedules

NovemberDevelop / ReviewSTRA/LTRA Data

Requests

DecemberSTRA/LTRA Data Requests Sent

to Regions

January – MarchRegional STRA Data Collection

Early-MarchSTRA Data Due to NERC

March-AprilNERC STRA Report Development

Late-AprilSTRA Release

January – JulyRegional LTRA Data Collection

JulyLTRA Data Due to NERC

July – SeptemberNERC LTRA Report

Development

NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC

DecemberLTRA Release

STRA: ORS/OC LTRA: RAS/PC


ERO-RAPA Group (Reports to ERO-EMG)• Membership: One member from each Regional Entity• Key Objectives NERC-Regional coordination and alignment Provide input for NERC assessments (including identification of key data, modeling,

analytics, and related tools) Support NERC in the identification of reliability issues Review NERC data requests Review NERC STRA and LTRA Presentation of Regional reports

Independent Input and ReviewERO-RAPA Group


Reliability Assessment Subcommittee (RAS) (Reports to PC)• Proposed Membership Existing RAS members (additional Assessment Area representatives) ERO-RAPA Members Existing RADWG members ORS Liaison

• Key Objectives Support NERC in the development and maintenance of LTRA data and narrative

requests Conduct data and narrative collection for the LTRA on an Assessment Area-basis Participate in the LTRA peer review of data and narratives for each Assessment Area Support NERC in the identification of long-term reliability issues

Stakeholder InvolvementReliability Assessment Subcommittee (RAS)


Operating Reliability Subcommittee (ORS) (Reports to OC)• Proposed Membership Existing ORS members Member from each Regional Entity Assessment Area representatives RAS Liaison

• Key Objectives Support NERC in the development and maintenance of STRA data and narrative

requests Conduct data and narrative collection for the STRA on an Assessment Area-basis Participate in the STRA peer review of data and narratives for each Assessment Area Support NERC in the identification of short-term and long-term reliability issues ORS to provide input to 2015-16 Winter Reliability Assessment

Stakeholder InvolvementOperating Reliability Subcommittee (ORS)


Assessment Development ProcessOverview

PCReview/Accept NERC LTRA

ERO-RAPARegional Coordination / AlignmentProvide input on Reliability Issues

Review/Comment on NERC Reports

RASLTRA Oversight &

Development

ERO-EMGProvide High-Level

Guidance/Feedback to ERO-RAPA on Assessments

NERC Board of TrusteesReview, Provide Feedback, and Approve NERC Reports

OCReview/Accept NERC STRA

ORSSTRA Oversight & Development

ORS/RASLiaison


• Substantial process development and implementation within a short timeframe (e.g., scope/charter adjustments) NERC staff will provide support for ensuring a smooth transition with special

attention to process• OC Strategic Plan Modification Seasonal assessments will be removed from PC; the STRA will be added to the OC

• ORS membership adjustments – can it be achieved by September 2015? A scope change will be needed to ensure Regional representation – specifically SMEs

familiar with operational analysis• Timelines for final data and information (i.e., alignment with other reports) ERO-RAPA is addressing Regional alignment and coordination

Short-Term Reliability Assessment Challenges and Concerns

PRC-005 Order No. 803 Directive NERC OC and PCJune 9-10, 2015Charles W. Rogers, Chair – Standard Drafting Team


• PRC-005 Development History• FERC Order 803 directive• Standards Authorization Request (SAR)• Proposed Methodology to address the directive• Proposed Implementation Plan• Standard development timeline

Topics


• PRC-005-0 – Approved by FERC in Order 693 Several minor revisions / interpretations through May 2012 September 2007 - SPCTF (now SPCS) presented report and SAR on PRC-

005 (and PRC-008/PRC-011/PRC-017) for PC approval October 2007 – SC approved posting SAR

PRC-005 Development History


• November 2007 – Project 2007-17 SDT began development of PRC-005-2 November 2012 – NERC BOT approved PRC-005-2

o Approved by FERC with several directives November 2013 – NERC BOT approved PRC-005-3 (Automatic Reclosing)

o Approved by FERC in January 2015 in order 803 with directives November 2014 – NERC BOT approved PRC-005-4 (Sudden Pressure

Relaying) – pending at FERC April 2015 – SDT revised PRC-005-4 to address directives from Order

803o Includes pending changes from Distributed Energy Resources SDT

and RAS/SPS SDT



• Distributed Energy Resources SDT Revised PRC-005-2 and PRC-005-3 to update applicability for

Distributed Energy ResourcesoPRC-005-2(i) and PRC-005-3(i)oDrafted PRC-005-5 to include all approved and pending

changes

• RAS/SPS SDT Revised PRC-005-2 and PRC-005-3 to reflect change from

SPS to RASoPRC-005-2(ii) and PRC-005-3(ii)



• In Order No. 803, FERC approved Standard PRC-005-3 and, in Paragraph 31, directed NERC to: "...direct that, pursuant to section 215(d)(5) of the FPA, NERC develop

modifications to PRC-005-3 to include supervisory devices associated with auto-reclosing relay schemes to which the Reliability Standard applies. Further, we clarify that NERC’s proposal regarding the scope of supervisory devices is an acceptable approach to satisfy the Commission directive. Specifically, NERC proposed in its NOPR comments, and we find acceptable, that the scope of the supervisory devices to be encompassed in the Reliability Standard are those providing voltage supervision, supervisory inputs associated with selective auto-reclosing, and sync-check relays that are part of a reclosing scheme covered by PRC-005-3."

FERC Order 803


• A revised Standards Authorization Request (SAR) was prepared along with a proposal to address the directive.

• The SAR provides background information regarding the directive.

• The existing Protection System Maintenance and Testing SDT (PSMTSDT) will work to address the directive.

SAR and Proposed Revisions


• The proposed solution that the PSMTSDT developed to address the directive proposes to revise the standard specific defined terms “Automatic Reclosing” and “Component Type”: Automatic Reclosing – Includes the following Components:

o Reclosing relayo Supervisory relay(s) – relays(s) that perform voltage and/or sync check

functions that enable or disable operation of the reclosing relayo Voltage and Current Sensing Devices associated with the supervisory

relay(s)o Control circuitry associated with the reclosing relay or supervisory relay(s).



• The proposed solution that the PSMTSDT developed to address the directive proposes to revise the standard specific defined terms “Automatic Reclosing” and “Component Type”: Component Type –

o Any one of the five specific elements of a Protection System. o Any one of the two four specific elements of Automatic Reclosing. o Any one of the two specific elements of Sudden Pressure Relaying.



• The PSMTSDT also proposes minor changes to Tables 4-1, 4-2(a) and 4-3(a). Adding supervisory relays where needed Other minor clarifying changes



• The PSMTSDT also proposes that a new table, Table 4-3, be added to address maintenance activities and testing for Automatic Reclosing with supervisory relays.


Table 4-3Maintenance Activities and Intervals for Automatic Reclosing Components

Component Type – Voltage and Current Sensing Devices Associated with Supervisory Relays

Component AttributesMaximum

Maintenance Interval

Maintenance Activities

Any voltage sensing device not having monitoring attributes of the category below.

12 Calendar Years

Verify that current and voltage signal values are provided to the supervisory relays.

Voltage sensing devices that are connected to microprocessor supervisory relays with AC measurements that are continuously verified by comparison of sensing input value, as measured by the microprocessor relay, to an independent ac measurement source, with alarming for unacceptable error or failure. (See Table 2)

No periodic maintenance

specifiedNone.


• The PSMTSDT proposes to streamline the Implementation Plan for all versions of PRC-005.

• PRC-005-2 and PRC-005-2(i) would be implemented together.• All other versions of the standard would be implemented

simultaneously with PRC-005-6. PRC-005-2(ii) PRC-005-3 PRC-005-3(i) PRC-005-3(ii) PRC-005-4 PRC-005-5

Proposed Implementation Plan


• The SAR and proposed methodology was posted for a 30-day informal comment period March 12 – April 10, 2015.

• The PSMTSDT met April 22-23, 2015 to review the comments on the SAR and to begin drafting revisions to PRC-005.

• NERC SC, at its May 20, 2015 meeting, directed that the SAR be revised to a new SAR and re-posted.

• Plan to post the SAR for industry review and revised standard and associated documents 30-day informal comment period in June 2015.

• PSMTSDT planning to meet via virtual conference in mid-July 2015 to address comments and revise the standard.

Standard development timeline


Information

• Senior Standards Developer, Steve Crutchfield Email at [email protected] Telephone: 609-651-9455

• Standards Developer, Jordan Mallory Email at [email protected] Telephone: 404-446-9733

• Chairman, Standard Drafting Team, Charles Rogers Email at [email protected] Telephone: 517-788-0027

• Project web page:http://www.nerc.com/pa/Stand/Pages/Project-201505-PRC005-Order-No-803-Directives.aspx

mailto:[email protected]



http://www.nerc.com/pa/Stand/Pages/Project-201505-PRC005-Order-No-803-Directives.aspx

Modeling Project UpdateNERC Interconnection Wide Modeling Update

Robert W. CummingsNERC Director of Reliability Initiatives and System AnalysisPlanning Committee MeetingJune 10, 2015


MOD-032 / -033 Implementation Schedule

MOD-032-1• July 1, 2015 — Effective date for R1 – Data collection

requirements and reporting procedure• July 1, 2016 — Effective date for R2, R3, and R4 – Data

collection begins

MOD-033-1• July 1, 2017 — Effective date for all requirements – System

model validation begins


• Governance process responsive to the needs of the interconnection PCs, Regions, the ERO and other users of cases

• Process with appropriate controls for dissemination of cases to qualified users

• Existing cases available to ERO, Regional Entities, RCs, PCs, TOs, and TPs without need for separate non-disclosure agreements

• Process for creating powerflow and dynamics cases for analysis of system events upon request of ERO or Regional Entities Section 804, 807, and 808 of the NERC Rules of Procedure

Draft Designee Functions


• All PCs in the interconnection must be included in the data collection process

• Develop and maintain a case creation manual for their interconnection

• Feedback loops to PCs and equipment owners for errors or problems found during case creation or quality and validation testing

• Process to prevent recurring problems data or models

Draft Designee Functions (continued)


• Use of standardized interconnection-wide dynamics models for equipment Temporary “unapproved” models allowed if an approved model is not yet

available or is under development

• Dynamic model change-control process requiring appropriate documentation – SME peer group to screen changes

• Process for case validation for the interconnection• Process for correcting cases already in use Immediate posting of modifications to cases for problems Notification of case users

Draft Designee Functions (continued)


Core Cases to be Created

Winter peak load case – for seasonal planning studies (interregional) and event analyses Also available for external models of outside world for operational

planning studies

Summer peak load case – for seasonal planning studies (interregional) and event analyses Also available for external models of outside world for operational

planning studies

Spring/Fall light-load case – for use in validation of Interconnection Frequency Response Obligations (IFROs) Also available for event analyses


Cases Needed for TPL-001-4 Studies

R2.1.1 – Planning Case for Year 1 System Peak Steady-State Analysis

R2.1.1 – Planning Case for Year 5 System Peak Steady-State Analysis R2.1.2 – Planning Case for Year 1 or Year 5 System Off-Peak Steady-

State AnalysisR2.4.1 – Planning Case for Year 1 or Year 5 System Peak Stability

AnalysisR2.4.2 – Planning Case for Year 1 or Year 5 System Off-Peak Stability

AnalysisR2.2.1 – Planning Case for Year 10 System Peak Steady-State

AnalysisR2.5 – Planning Case for Year 10 System Peak Stability Analysis


• Solicitation for designees – next couple of weeks Distribute Designee Functions and Attributes Distribute Project Plan

• Select designee by end of 3rd quarter

Next Steps

Order No. 754 Data RequestSubmission of Report and Recommendations

Phil Winston, SPCS ChairJohn Simonelli, SAMS ChairNERC Planning CommitteeJune 9-10, 2015


• Review of data is complete

• Investigation of Misoperation data to correlate relative reliability risk among different protection system component failures is complete

Status Report – Overview


• Background• Analysis of Data• Discussion of Alternatives TPL Reliability Standard revisionso Modify footnote 13 to include, at a minimum, protective relays and dc control

circuitry o Place additional emphasis on assessment of extreme events involving a three-

phase fault and protection system failure Reliability Guidelineo Provide insight into modeling protection system failures in planning assessmentso Provide insight into evaluation of risk of a single point of failure

NERC Alerto Raise awareness based on findings from the data request

• Conclusions and Recommendations

Report Outline


• Analysis of the data has identified a reliability risk that warrants further action

• Risk-based assessment was used to identify protection systems of concern Not all failures equally affect reliable operation of the Bulk-Power System Reliability effect varies based on which component fails

• Assessments should address, at a minimum, single points of failure in protective relays, single-station dc supply, and dc control circuitry

Conclusions


• For TPL-001-4, Table 1 – Steady State & Stability Performance Planning Events, Category P5: Replace “relay” with “component of Protection System” Continue to reference footnote 13

• For TPL-001-4, Table 1 – Steady State & Stability Performance Extreme Events, under the “Stability” column, No. 2: Remove the phrase “or a relay failure13” from items a, b, c, and d to create

distinct events only for stuck breaker.

Recommendations


• Replace footnote 13 in TPL-001-4 with, The components from the definition of “Protection System” for the purposes of this standard include:

(1) protective relays which respond to electrical quantities,

(2) single station dc supply that is not monitored for both low voltage and open circuit, with alarms centrally monitored; i.e., reported within 24 hours of detecting an abnormal condition to a location where corrective action can be initiated, and

(3) dc control circuitry associated with protective functions through the trip coil(s) of the circuit breakers or other interrupting devices

Recommendations


• Modify TPL-001-4 (e.g. , in Part 4.5) so that extreme event assessments must include evaluation of the three-phase faults with described component failure of a Protection System that produce the more severe system impacts.

For example, add a new second sentence stating, “The list shall consider each of the extreme events in Table 1 – Steady State & Stability Performance Extreme Events; Stability column item number 2.”

Recommendations


• Provide at least three PC reviewers to do a thorough review with comments due by July 10th

• Provide the report to all PC members for review of recommendations

• Seek approval of the report at the September PC meeting.

Requested Action

Revisions to Power Plant and Transmission System Protection Coordination Technical Reference DocumentPhil Winston, SPCS ChairNERC Planning Committee June 9-10, 2015


• Power Plant and Transmission System Protection Coordinationreport approved by PC in December 2009 Addresses and expands upon protection system coordination concerns

from the August 14, 2003 blackout Approved by the PC in December 2009 Revision 1 approved by the PC in July 2010

• Revision 2 addresses comments from the IEEE Power System Relaying Committee and other industry stakeholders Approved for posting for 45-day public comment period by the PC in June Posted for comment through August 1 Comments received from 13 entities and 1 PC member SPCS has reviewed comments and updated the document.

Background and Timeline


Major Updates:• Phase Distance Protection (Function 21)• Loss-of-Field Protection (LOF) — Function 40• Voltage-Controlled or Voltage-Restrained Overcurrent

Protection (Function 51V)• Stator Ground Protection (Function 59GN/27TH)• Out-of-Step or Loss-of-Synchronism Protection (Function 78)

Various figures updated and renumbered

Overview of Technical Changes


• Include guidance on protection as well as coordination• Reflect coordination of transmission devices with generator devices in

coordination definition• Discuss coordination of generator undervoltage protection with auxiliary

equipment undervoltage protection and UVLS• Differentiate where guidance is dependent on plant configuration (e.g., GSU

winding connections, generator neutral impedance)• Discuss low fault current considerations for breaker failure protection• Discuss presence of overexcitation and voltage trip functions in excitation

systems• Note inadvertent energization protection is sometimes a Transmission

Owner function• Note susceptibility of third harmonic protection to coupled voltage when the

GSU high-side is not grounded

Overview of Additional Technical Comments


• Add a disclaimer to emphasize the report is “for technical guidance only . . . and does not impose mandatory requirements subject to compliance”

• Reference associated NERC standards – use current revision or general reference

• Assure references to figures are specific and clear• Consistent capitalization and hyphenation of terms• Use of Bulk Electric System versus Bulk-Power System• Use of Planning Coordinator versus Transmission Planner• Refer to ANSI device number for multi-function devices

Overview of Editorial Comments


• Use of terms such as “required” and “must” , “ensure” vs “assure”

• Emphasize benefits to Generator Owners of avoiding unnecessary trips

Overview of General Comments


• The SPCS has provided a clean and redlined version of the document

• The SPCS is seeking endorsement of the revision to the Technical Reference Document and permission to post on the NERC SPCS site

Requested Actions

Periodic Review of System Operating Limit Standards

Jason Smith, Southwest Power Pool Planning Committee MeetingJune 10, 2015


• Project 2015-03 Periodic Review of System Operating Limit Standards includes three FAC standards: FAC-010-3 SOL Methodology for the Planning Horizon FAC-011-3 SOL Methodology for the Operations Horizon FAC-014-2 Establish and Communicate SOLs

• These standards were delayed from the 2013 periodic review of FAC standards until completion of TOP and IRO standards project and FERC approval of TLP-001-4 (October 2013)

• Periodic review is required by the NERC Standards Process Manual

FAC Periodic Review Overview


• Objective: determine whether to affirm, revise, or retire Periodic Review Recommendations (PRRs) posted for comment through

June 17 One PRR is posted for each of the three FAC standards in the project

• Inputs: Federal Energy Regulatory Commission (FERC) directives Stakeholder requests for clarity or revision Paragraph 81 principles Independent Expert Report recommendations Consistency with other Reliability Standards

Periodic Review Overview


Project 2015-03 Periodic Review Team


• The purpose of FAC-010-3 is:To ensure that System Operating Limits (SOLs) used in the reliable planning of the Bulk Electric System (BES) are determined based on an established methodology or methodologies.

• FAC-010 requires the Planning Coordinator (PC) to have a methodology for developing SOLs in the planning area

• Few changes have been made to the standard since version 2 was adopted in 2008

Summary of FAC-010-3


• Current requirements in FAC-010 either: Provide little or no reliability benefit, or Are duplicative of requirements in TPL-001-4

• TPL-001-4 provides the details for planning the System and criteria for performance, eliminating the need for a separate methodology

• Proposed standards project to retire FAC-010 should also develop requirements to ensure reliability information needed to establish SOLs and IROLs is passed from the PC to the Reliability Coordinator (RC). Information such as instability risks to address through operating limits Requirements could be added to FAC-014 or TPL-001-4

PRT Recommendation – FAC-010


• The purpose of FAC-011-3 is:To ensure that System Operating Limits (SOLs) used in the reliable operation of the Bulk Electric System (BES) are determined based on an established methodology or methodologies.

• FAC-011 requires the RC to have an SOL methodology that provides for acceptable BES performance

• Few changes have been made to the standard since version 2 was adopted in 2008



• The purpose of FAC-014-2 is:To ensure that System Operating Limits (SOLs) used in the reliable planning and operation of the Bulk Electric System (BES) are determined based on an established methodology or methodologies.

• FAC-014 requires the establishment and communication of SOLs and Interconnection Reliability Operating Limits (IROL)



• PRT is seeking stakeholder comment on PRRs to revise FAC-011 and FAC-014

Issues to address:• Presumptions in FAC-011-3 and FAC-014-2 do not fit with

today’s operational paradigm• Improve alignment with proposed TOP and IRO standards and

with the NERC SOL White Paper • Inconsistent application and confusion with the System

Operating Limit (SOL) defined term• Unclear requirements or gaps in responsibility for determining

some limits• FERC directive

Recommendation: FAC-011 and FAC-014


• Much confusion with – and many widely varied interpretations and applications of – the SOL term Project 2014-03 developed White Paper to promote clarity, consistency,

and a common understanding of the concepts associated with establishing SOLs, exceeding SOLs, and implementing Operating Plans to prevent and mitigate SOL exceedance.

White Paper served as a context for new TOP/IRO standards

• A revised definition of SOL and new defined term SOL Exceedance are proposed to improve clarity and alignment with proposed TOP and IRO standards and NERC SOL White Paper

• Revised TOP and IRO standards are pending regulatory approval

System Operating Limit Confusion

NERC SOL White Paper: SOL Definition and Exceedance ClarificationPRT White Paper: Rationale for Revising the Definition of SOL

http://www.nerc.com/pa/Stand/Prjct201403RvsnstoTOPandIROStndrds/2014_03_fifth_posting_white_paper_sol_exceedance_20150108_clean.pdf

http://www.nerc.com/pa/Stand/Prjct201503PrdcRvwofSstmOprtngLmtStndrdsDL/Rationale%20for%20SOL%20Definition_May4.pdf


• In Order No. 777 approving FAC-003-1, the Commission directed: “NERC should establish a clearly defined communication structure to assure that IROLs and changes to IROL status are timely communicated to transmission owners.” (P. 42)

• Revised FAC-014 standards should include Transmission Owners among entities to receive information on IROL Facilities

Applicable FERC Directive


• Draft recommendations and supporting material are posted for 45-day comment period from May 4 – June 17, 2015

• Comment review and SAR development will begin in June 2015

Project Status

Project Page: http://www.nerc.com/pa/Stand/Pages/Project-2015-03-Periodic-Review-of-System-Operating-Limit-Standards.aspx

http://www.nerc.com/pa/Stand/Pages/Project-2015-03-Periodic-Review-of-System-Operating-Limit-Standards.aspx

Geomagnetic DisturbancesGMD Task Force and Standards Update

Ken Donohoo, OncorPlanning Committee MeetingJune 10, 2015


• Requires a Geomagnetic Disturbance (GMD) Vulnerability Assessment of the system to determine its ability to withstand a benchmark GMD event without causing voltage collapse Assessment performed once every five years Applicability: Planning Coordinators and Transmission Planners

• Requires a transformer thermal assessment of high-side, wye grounded Bulk Electric System (BES) transformers connected at 200kV or higher where effective GIC ≥ 75 A per phase Applicability: Transmission Owners and Generator Owners

TPL-007 Summary


• TPL-007-1 was approved by the NERC Board in December 2014 and filed for regulatory approval on January 21, 2015

• Panel of NERC Board members will hold meeting on June 29, 2015, to hear a standards process appeal filed in February 2015 Foundation for Resilient Societies participated as a stakeholder in the

development process and objects to TPL-007-1 on technical grounds

• Notice of Proposed Rulemaking (NOPR) issued May 14, 2015 Proposes to approve TPL-007-1: “…the proposed standard addresses the

directives in Order No. 779…” NOPR public comment period through July 27, 2015 (RM15-11)

Standards Project Status


• FERC proposes modifications to the benchmark GMD event to address their concerns with ‘spatial averaging’ technique The averaging of calculated geoelectric fields from a network of

magnetometers is used to describe the effects of GMD events over an area The technique is used to avoid bias from localized peak magnetic deviations FERC also proposes to direct installation of monitoring equipment to

validate the benchmark GMD event

• FERC proposes deadlines for completing corrective actions Two years for operating procedure mitigation measures Four years for hardware-based mitigation measures

• NERC may be directed to submit a work plan of GMD research and informational filings

NOPR Issues


TPL-007 Implementation Plan

Date of Approval

6 Months•R1•Identify Responsibilities

18 Months•R2•System Models

24 Months•R5•GIC Flow Information

48 Months•R6•Thermal Assessment

60 Months•R3, R4, and R7•GMD Assessment•Corrective Action Plan


• GMD TF transformer thermal modeling guide is in development Transformer manufacturer provided report of modeling data and analysis in

April 2015 per EPRI contract GMD TF analysis and development of initial draft modeling guide is underway

• NERC and EPRI contract continues GMD support in 2015-2016 and is focused on addressing further technical challenges Development of tools to support assessment of harmonic impacts from GMD Improved ground conductivity models Education and training for standards implementation

• NOPR issues will be factored into future research

GMD TF Project Plan Update

System Analysis and Modeling Subcommittee and Modeling Working GroupUpdate

John Simonelli, Chair System Analysis and Modeling SubcommitteePlanning Committee MeetingJune 9, 2015


SAMS Task Update for June PC Meeting

SAMS current efforts focusing on:• Working with SPCS to finalize order 754 report• Working with EPRI on development of a GMD Study Guideline

pending final FERC order• Work with DOE to host a FIDVR/Composite Load Modeling

workshop Fall 2015, date and location TBD Review R&D and industry efforts Discuss potential impacts to NERC standards Develop goal for load modeling moving forward



• Follow up on NERC 10/WECC 21 recommendations on Generator Control & Acceleration Control Functions MWG will solicit volunteers from Generator manufacturers and the NAGF

to establish an industry-wide SME team to work on the issue

• Support RAS standards drafting team• Monitoring FAC-010/-011/-014 standards rewrite • Work with NERC Staff to compile a Sub-synchronous

Resonance/Control Interaction industry reference document library



SAMS future efforts under consideration subject to scoping and prioritization:• Develop a study guide for solar/wind penetration• Develop a whitepaper dealing with modeling 3-phase systems

to address more detailed generator interactions• Develop guidelines for dynamic load modeling and conducting

FIDVR analysis• Develop guidelines for conducting harmonic and flicker analysis



• Follow-up on any recommendations from the ERSTF• Follow-up on any recommendations from the IVGTF• Develop a guideline for analyzing ferroresonance• Coordinate with NASPI on conducting generator validation

using PMU data• Continue research into governor modeling, governor data for

modeling and governor real-time performance


MWG Task Update for June PC Meeting

MWG current efforts focusing on:• SAMS recommended and the PC approved a seven year

transition period for the industry to move to development and maintenance of node-breaker representations for off-line and real-time study models

• The transition was broken up into six distinct tasks culminating in implementation in 2020



Task One: Establish a uniform structure for elements in the topology and the parameters for exchange of node-breaker models (Complete)

Task Two: Establish data exchange format and write specification for software developers (Complete)


MWG Task Updates for June PC Meeting

Task Three: Develop criteria for additional tools and functionality (Dec 2017)• This step within the transition plan includes: Criteria for topology processing Criteria for automated contingency recognition Collapsibility of topology details from node-breaker representation into

bus-branch representation

• Vendor development is once again ahead of the transition plan



• MWG will meet with Siemens to review the new node-breaker functionality provided in the recent PSSE Rev 34 release.

• GE will be releasing a new version of PSLF which will contain node-breaker functionality.

• MWG will meet with GE once the new release is out.



Task Four: Conduct a small-scale pilot program with interested Regions or Areas (Dec 2018)• Using both the Siemens PSSE Rev 34 and the expected GE PSLF

release, MWG will solicit industry volunteers to test the applications.

• The results of the testing will be reported to SAMS and the PC.



Follow-up on Model validation Field Trial• PC approved the “Procedures for Validating Powerflow and

Dynamics Cases.” and solicited volunteers to valid the procedures

• MWG has collected feedback from several entities• MWG will publish the final document• MWG and EPRI will have panel session at the IEEE Summer

meeting in Denver to promote model validation techniques



MWG continuing efforts to develop proposal for Use of Standardized Component Models in Powerflow and Dynamics Cases• Need to work with NERC legal to publish documents• Need to develop change management process


General Update for June PC Meeting

• Chuck Chakravarthi from Southern Company will step down as SAMS Vice-chairman

• Michael Lombardi from NPCC will become the new SAMS Vice-chairman

• Ryan Quint of NERC Staff will join SAMS as the new NERC coordinator replacing Neil Burbure

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