Planning Committee Charter Update Highlights and...Probabilistic Assessment Guidelines document. • NERC-Regional Coordinated Special Assessment Expand the probabilistic study efforts

Planning Committee Charter Update

Elliott Nethercutt, PC SecretaryPlanning Committee MeetingJune 7, 2016

RELIABILITY | ACCOUNTABILITY2

Planning Committee Charter Background and Proposed Enhancements

Background• Last charter update: November 2013• Change in NERC’s strategic direction drives the need for clarity

on processProposed Enhancements• Provide definitions and processes for deliverable approval,

endorsement, and acceptance• Define PC deliverables (e.g., white papers, technical reports,

technical reference documents)• Add clarity and consistency for PC subgroups (charter

alignment)• Add clarity for PC Executive Committee delegation responsibility


Planning Committee Charter Update Proposed Development Schedule

• April: Introduced proposed charter addendum to PC Leadership and Executive Committee

• Late-May: Direction from NERC Legal Department regarding Board approval

• June 7-8 PC Meeting: Introduce proposed charter updates• June 20 – July 1: Two-week review period for the Planning

Committee• July 5-6: NERC staff responds to PC Comments• July 6-8: PC electronic vote for endorsement of charter for

Board approval• August 10-11: NERC Board of Trustees approval vote


1 RELIABILITY | ACCOUNTABILITY

PC Annual ElectionMembers/Sectors Open or Up for Renewal

Member Name, Organization Sector Y/NGary T. Brownfield, Lower Colorado River Authority Investor-Owned Utility ?Arthur Iler, American Municipal Power, Inc. State/Municipal Utility YRuss Schussler, Georgia Transmission Corporation Cooperative Utility ?Stephane Talbot, Hydro Québec TransÉnergie Provincial Utility (CA) YDavid Jacobson, Manitoba Hydro Provincial Utility (CA) ?Brian Zavesky, Missouri River Energy Services Transmission Dependent Utility YRobert Ramaekers, Tenaska, Inc. Merchant Electricity Generator YSteven Huber, Public Service Enterprise Group Electricity Marketer ?Vacant Large End-Use Electricity Customer -John Hughes, Electricity Consumers Resource Council Large End-Use Electricity Customer NHerb Schrayshuen, Self-as Small End-User Small End-Use Electricity Customer ?Mark Sims, PJM ISO/RTO NVacant State Government -Vacant State Government -

NERC 2016 Summer Reliability AssessmentPooja Shah, NERC StaffPlanning Committee MeetingJune 7-8, 2016


• 2016 Summer Reliability Assessment (2016 SRA) Process Layout – New Format for the SRA Key Findings Timeline

• Request the Planning Committee (PC) Accept the 2016 SRA

Introduction


• Data Collection for 2016 SRA – Reliability Assessment Subcommittee (RAS) Minimal data requests and no narratives

• Data Validation – RAS and NERC Staff• RAS Meeting – April 2016 Area/Regional presentation on the upcoming summer Abbreviated Peer Review Key findings identified

• Report Development – NERC Staff• Comments/Review/Edits – incorporated from PC Members NERC Management RAS Members

Process


New Format for Summer Assessment

Description of Region/Assessment Area

On-Peak and DeratedRenewable Capacity

Fuel mix for a Region/Assessment Area

Resource and Demand Table (Same as SRA Reports)

Key Findings


• Anticipated Reserve Margin forecasted to be above the Reference Margin Level for all Assessment Areas and Regions

• Aliso Canyon Gas Storage Facility Outages remains a concern CAISO is working with relevant entities to ensure the expected days of load

shedding are minimized

Key Findings


2016 SRA - Remaining Timeline

Deliverable Deadline Status

Send to PC for Review May 23 Complete

Incorporate PC Comments May 23 – June 6 Complete (withcomments rec’d to date)

Send to NERC Management for Review May 23 – June 6 Complete

Incorporate NERC Management comments May 23 – June 6 Complete

Send revision of SRA to PC for review of NERC Management edits/comments

May 31 Complete

PC Meeting: SRA Presentation and Vote for Approval June 7-8 Pending

Send report to Publications June 8 Pending

Send report to NERC Executive Management June 10 Pending

Report Release June 14 Pending


Request PC Action: Accept 2016 Summer Reliability Assessment


Pooja ShahSenior Engineer, Reliability Assessment404-446-9621 office | 404-710-0502 [email protected]

mailto:[email protected]

Gas-Electric Interdependency Special Short-Term Assessment

John Moura, Director, Reliability Assessment and System AnalysisOC/PC MeetingsJune 7-8, 2016


Introduction

• Gas-electric interdependency STSA: This first STSA was approved by the OC and PC in April and released in

May. Review of report highlights and findings

• Second STSA: NERC, in coordination with the Reliability Assessment Subcommittee

(RAS), the ERO RAPA is in the process of identifying an assessment topic. The PC and OC are invited to suggest topics for consideration


Overview

• Industry continues to coordinate between the two industries Electric Natural Gas

• Historically, reliability concerns in winter Report finds summer season can also be impacted

• Aliso Canyon storage facility – will not be refueled for summer 2016


• The electric and gas industries should consider mitigation measures – use of dual-fuel generators and firm natural gas delivery contracts.

• Risks to natural gas generation during summer season – not just a winter problem

• Expand gas-electric planning and coordination – current industry best practice in some areas

• Operational coordination between gas and electric industries decrease likelihood of wide-spread outage

Key Findings and Recommendations


NERC’s Annual Long-Term Projection

2009 LTRA

2011 LTRA

2013 LTRA

2015 LTRA

320

330

340

350

360

370

380

390

400

410

420

430

440

450

460

470

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

GWTotal NERC-Wide On-Peak Gas-Fired Capacity


Assessment Summary

• Generation Availability Risk Assessment• Assessment Period: Peak periods for Summer 2016, 2017;

Winter 2016/17, 2017/18• Short-term challenges related to natural gas infrastructure• Leverage existing studies from industry and Regions

Areas Highly-Dependent on Natural Gas-Fired Capacity


Gas Availability Risk Assessment

Average Forced Non-Gas Outages

Average Forced Gas Outages

Maximum Forced Gas Outages (in excess of average)Gas-Fired

Capacity

Dual-FuelCapacity

Non-Gas-FiredCapacity

Based on GADS Performance Data

Extreme (90/10) Peak Load Forecast

Normal (50/50) Peak Load Forecast

Firm Import Capability

Separate Area-Specific NG ScenarioRefers to loss of a major pipelines during the peak


Results – ISO-NE

ISO-NE Summer 2016 Gas Operational Risk

0

5

10

15

20

25

30

35

AnticipatedCapacity

Net Imports (Firm) At-Risk Capacity Extreme Scenario

GW


Results - NYISO

NYISO Summer 2017 Gas Operational Risk

0

5

10

15

20

25

30

35

40

45

AnticipatedCapacity


GW


Results - ERCOT

ERCOT Winter 2016/17 Gas Operational Risk

0

10

20

30

40

50

60

70

80

90

AnticipatedCapacity


GW


Results – WECC CA/MX

CA-MX Winter 2017/18 Gas Operational Risk

0

10

20

30

40

50

60

AnticipatedCapacity


GW


• Aliso Canyon is a critical element of the Los Angeles Basin natural gas delivery system Supports winter peak heating demand Maintains pressure in gas distribution system (More challenging with rapid

power plant ramping)

• Aliso Canyon currently has about 15 Bcf of working gas out of a total capacity of 86 Bcf

• Injections will not resume until safety testing or isolation of remaining 114 wells is completed

Aliso Canyon: Basics


Aliso Canyon: LA Basin Power Supply


• Fuel availability for local generation may be impacted for upcoming summer Gas system deliverability without Aliso Canyon Gas system outages (SoCal or on interstate pipelines) Exogenous factors affecting supply (e.g., cold weather) Curtailment priorities

• Generation resource adequacy 95% of in-basin generation vulnerable to gas curtailment Adequate generation resources exist to supply imports into the LA Basin,

but this does not take into account local deliverability issues

Aliso Canyon: Anticipated Interruptions


Short-Term Special AssessmentProposed List of Topics for STSA #2

1. Accelerated Nuclear Retirements2. Off-Peak Load Seasonal Assessment3. August 2017 Solar Eclipse4. Variable Resource Curtailments5. Natural Gas Single Point of Failure Analysis

• Other topics are being considered by Regional stakeholder groups


Phil Fedora, RAS Chair Planning Committee Meeting June 7-8, 2016

Reliability Assessment Subcommittee Status Update

RELIABILITY | ACCOUNTABILITY 2

June 10, 2016 LTRA data due

June 24, 2016 Draft Narratives Due

June 29-30, 2016 RAS Conference Call

July 1, 2016 Peer Review Comments Due

July 12-13, 2016 RAS Meeting – SERC office

July 22, 2016 Final Data & Narratives Due

July - September LTRA Report development by NERC Staff

Upcoming LTRA Milestones

Upcoming milestones for the development for the 2016 Long-Term Reliability Assessment (LTRA)


2016 Reliability Assessment Reports LTRA Overview

2016 Long-Term Reliability Assessment Primary/Supplemental Data and Informational Requests Ongoing MMWG coordination Incorporation of : Essential Reliability Services Measure 6 – Net Demand Ramping Variability Probabilistic Dashboard Results

Continuing need to clarify instructions: Distributed Generation On-Peak Capacity Transfer capability Planned Generation Tiers:

2016 Probabilistic Assessment Q1 – 2017 target release


Net Demand Ramping Variability Essential Reliability Services (ERS) Working Group working on: Ramping Screening Methodology – to be used in the LTRA for

identification of existing/potential ramping reliability concerns Identified LTRA ramping reliability concerns – to be considered

in the development of the ERS Sufficiency Guidelines

Essential Reliability Services Measure 6


Probabilistic Assessment Improvement Task Force Guideline Document Proposed Probabilistic Enhancements Probabilistic Metrics Study Year(s)/Frequency Scenario Analysis

Reliability Assessment Subcommittee Probabilistic Assessment Improvement Task Force


Remaining LTRA Timeline (as of May 23, 2016)

2016 LTRA Schedule Date Action Item

August 23-24 ERO RAPA Meeting: review of Regional responses to narrative questions September 2 Draft report sent to RAS (Prober dashboards NOT included) September 23 RAS comments due to NERC September 26-30 NERC responds to RAS comments October 4 RAS Meeting; Conference Call; Prober Team presents to RAS October 14 Prober dashboards/narratives due to NERC October 17-21 NERC incorporates Prober dashboards and addresses ERS Measure 6 in the report

October 21 LTRA sent to PC for review October 21-November 4 PC review period

November 4-8 NERC responds to PC feedback November 8 PC webinar for report endorsement November 8-18 NERC Editorial Review November 14-16 RAS Meeting; FRCC - Tampa FL; WRA/STSA/LTRA November 21 LTRA sent to NERC Executive Management, MRC, and ERO RAPA November 21-25 NERC Executive Management, MRC, and ERO RAPA review period November 25-28 NERC responds to feedback from NERC Executive Management and MRC

November 28 LTRA sent to NERC Board of Trustees November 28- December 5-6 (awaiting confirmation)

NERC Board of Trustees review period

December 5-8 (awaiting confirmation)

NERC Board of Trustees conference call to vote on report approval

December 8-13 NERC responds to feedback from Board of Trustees December 13 Target Release


Probabilistic Assessment Guidelines

Noha Abdel-Karim, PhD., Senior Engineer for Reliability AssessmentPlanning Committee MeetingJune 7-8, 2016


• Background: Prepare Probabilistic Assessment Guidelines document to Identify modeling requirements and recommendations, and to support Regional scenarios to study emerging risks to reliability.

• Core Probabilistic Assessment Continuation of the individual area probability

assessments. Modeling consistency will be improved by following a

Probabilistic Assessment Guidelines document.

• NERC-Regional Coordinated Special Assessment Expand the probabilistic study efforts with NERC and the

Regions leading the development and evaluation efforts of additional scenario studies on reliability concerns related to the BPS higher risk areas identified in the LTRA.

Probabilistic Assessment Guidelines Document Overview


• Core Probabilistic Assessment Metric Reporting Areas Metrics Descriptions Metric Calculations Probabilistic Study Reportingo Study Frequency and Study Years

Simulation software

• Coordinated NERC Regional Special Assessment Special Assessment Determination Roles and Responsibilities Modeling Requirements and

Scope of Work

• General Modeling Assumptions Load Modeling Capacity Modeling Emergency Operating Procedures Transmission Modeling Sensitivity and Scenario Modeling Data Preparation and Collection

ProbA Guidelines Document


• Primary objectives• Enhancements Summary• Probabilistic Metrics• Assessment Frequency• Sensitivity and Scenario • Enhancement Applicable to the 2016 ProbA Development

Probabilistic Guidelines


• Identify practices, requirements and recommendations needed to perform high-quality probabilistic resource adequacy assessments.

• Complement reserve margin analyses in NERC’s Long-Term Reliability Assessments by producing enhanced resource adequacy metrics and modeling approaches.

• Provide NERC and policy makers with far greater insight, understanding, and the perspectives on BPS reliability.

• Support regional scenarios to study reliability issues identified in the Long-Term Reliability Assessment.

ProbA Guidelines


ProbA Guidelines

Enhancements Summary

NERC should develop and maintain documentation describing the establishment of Assessment Areas. 1

Regions and Assessment Areas should provide monthly reliability measures in their metrics calculations.2

Regions and Assessment Areas should incorporate seasonal variations in their load modeling.3

Regions and Assessment Areas should capture seasonalcapacity ratings in generation models.4


ProbA Guidelines

Enhancements Summary

Flexibility should be maintained in transmission modelingfor each Assessment Area.5

Assessment Areas should coordinate with neighboring areasto determine the appropriate amount of capacity transfers.6

NERC, within the RAS, should determine candidate probabilistic sensitivity analysis and scenario models to study.7


• Probabilistic Metrics Annual LOLH Monthly LOLH Annual EUE, both actual and normalized Monthly EUE, both actual and normalized

• Probabilistic Study Frequency and Study Years With inputs from the RAS, RAS-ProbA, PAITF and ERO-RAPAo Probabilistic assessment is on a biennial basis

Assessment Areas study both year 2 and 4 of the Long-Term Reliability Assessment (LTRA).

Year 2 reporting is to track and trend resource adequacy measures assessment to assessment.

ProbA Guidelines


• Assess the impact of a change in an input (either load, transmission or resource-related) on resource adequacy metrics.

• The runs are performed by changing one input at-a-time in order to isolate the potential impact of each input.

• Ideally, the change in each input should be accompanied by an associated probability.

• The sensitivity modeling should be addressed within the Core Probabilistic Assessment framework.

• Assess the impact of changes in multiples inputs (either load, transmission or resource-related) on resource adequacy metrics.

• The runs are performed by changing multiple inputs at the same time

• Scenarios are likely to be identified in the LTRA or by sensitivity analysis results.

• The scenario modeling should addressthe reliability issues identified withinthe LTRA that impact resourceadequacy, within the Special-Coordinated Probabilistic Assessmentframework

ProbA Guidelines

Scenario ModelingSensitivity Modeling


• 2016 ProbA Enhancements Monthly Probabilistic Measures Per guidelines, Assessment Areas describe in their narratives the

assumptions used to develop ALL modeling categories of their probabilistic studies.

ProbA Guidelines


2016 ProbA Schedule


• Request from the PC to: Assign PC Reviewers to the ProbA Guidelines document Seek PC Approval of the ProbA Guidelines document after an adequate

reviewing time and via an electronic vote

Actions


Reliability Guideline:Reactive Power Planning and OperationsPlanning Committee Approval for Industry Comment

Bill Harm, PJMPlanning Committee MeetingJune 7-8, 2016


• System Analysis and Modeling Subcommittee (SAMS) is asking the Planning Committee (PC) for approval of the “final draft” guideline for NERC posting for industry comment 45 days for industry comment period as per the PC Charter

• The SAMS sub-team will then reconvene to consider industry comments and develop final draft for PC approval This will be an industry developed NERC document

• Different than the previous Technical Issues Subcommittee (TIS) reactive white paper TIS forwarded a final document to the PC for approvalo Action items were incorporated in VAR-001, Var-002 and TPL-001

Reactive Guideline - Administrative


• Provide guidance and direction related to modeling, study, and placement of reactive power resources to support robust voltage profiles. NERC’s mission of improved reliability through sharing industry practices

for planning and operating the BPS

• Guideline applies primarily to: Planning Coordinators Transmission Planners Transmission Operators Generator Operators Generator Owners Reliability Coordinators

Reactive Guideline - General


• Two parts: Technical Document Appendices and References

• First part includes: Background on reactive planning and operations Summary of Relevant NERC standards o TPL-001o VAR-001; VAR-002o TOP-004

Technical discussion regarding reactive power analysiso Strategies center around the need for static and dynamic reactive power

resource planning and operational planning

Reactive Guideline - General


• Assessment tools and techniques• Time frames – pre-contingency through disturbance and new

post contingency steady state Transient, midterm dynamics, long term dynamics, post contingency

steady state• Determining steady-state voltage limits and post-contingency

voltage deviations PV analysis QV analysis

• Transient Analysis

Reactive Guideline - Analysis


• Fundamentals of voltage control and static and dynamic reactive resources

• Deriving voltage schedules on Trans system Typical Operating voltage schedules

• Generator voltage control Converting visible generator voltage to the transmission system

• Transient voltage response criteria• Protecting against voltage instability• Determining sufficient reactive resources and/or margins to

regulate voltage levels under normal and contingency conditions

Reactive Guideline – Voltage Criteria


• Reactive power generation scheduling• Automatic voltage control modes• Coordination with static devices and other controls• Reactive Reserve Requirements• Dynamic reserves vs. static• Addressing “sufficient” reserves

Reactive Guideline – Voltage Control


• Interface coordination between operating entities• Distribution of reactive resources among transmission,

distribution, and generation

Reactive Guideline –Interface Coordination


2nd part of guideline includes:• Appendix A – Industry Reactive Power Planning Practices &

Procedures Analysis tools, techniques, planning horizons, and relevant reference

materials from an array of entities across North America How the information contained in the first part of the guideline is applied

in operations and planning

• Appendix B – Transient Voltage Response Criteria Practices Response criteria as per NERC Reliability Standard TPL-001-4 Requirement

R5 and a description of the criteria developed

Reactive Guideline – Appendices


• 6/8/2016 - PC Approval for Posting for Industry Comments• 8/1/2015 - 45 Day Comment Period Complete (6/15 Posting)• 8/15-10/27 - Response to Comments & Document Revision• 10/27/2016 - SAMS Approve Final Draft at SAMS Meeting• 12/13/2016 - PC Final Approval

Reactive Guideline – Timeline


Reliability GuidelinePower Plant Model Verification using PMUsPlanning Committee Approval for Industry Comment

Ryan D. Quint, NERCPlanning Committee MeetingJune 7-8, 2016


• NERC Synchronized Measurement Subcommittee (SMS) is requesting Planning Committee (PC) approval for industry comment period of the Reliability Guideline for Power Plant Model Verification using PMUs

• The SMS will reconvene to address industry comments and develop final draft for PC approval in September

• Timeline: June 7-8: PC approval for posting for industry comment June 15-July 30: 45-day comment period August 1-Sept 1: SMS response to comments and edits to draft RG Sept PC Meeting: PC final approval

PPMV Guideline: Overview


Drivers:• Provide technical guidance and direction for performing

disturbance-based verification using PMUs as one option for model verification

• Provide guidance for MOD-026 and -027 Requirement R2: The [GO] can use disturbance-based model verification as a form

of demonstrating that the modeled response matches actual response. However, this must also be accompanied by the other documentation and data required by Requirements R2, including manufacturer data, model structure and data, compensation settings, etc.

Requirement R3: The [TP] can use results from disturbance-based model verification to demonstrate that the current model being used does not accurately represent actual response.

Requirement R5: The [TP] can submit a request for model review using “technically justified” results “demonstrating that the simulated unit or plant response does not match the measured unit or plant response.”

PPMV Guideline:Drivers


Applicability:• Transmission Planners• Planning Coordinators• Transmission Owners• Generator Owners

PPMV Guideline:Drivers


• Document Covers: Fundamental need for representative models Power Plant Model Verification (PPMV) Offline Baseline Testing for pro forma Model Online Performance Monitoring Process for Model Validation Value Proposition for Disturbance-Based Verification Related NERC Reliability Standards Performing PMU-Based Model Verificationo Procedure Overviewo Measurement & Modeling Considerationso Event Selection

Disturbance-Based Verification Examples Library Appendix – Software Tools Guidelines

Power Plant Model Verification


Phase Angle MonitoringTechnical Report Follow-Up and Approval

Ryan D. Quint, NERCPlanning Committee MeetingJune 7-8, 2016


• NERC Synchronized Measurement Subcommittee (SMS) sought Planning Committee (PC) approval on Phase Angle Monitoring Technical Report at the March 2016 PC meeting. Questions about recommendations; wanted feedback from the Operating

Committee prior to approval. Convened review team to provide comments and address any concerns.

• Will describe changes and updates since last meeting.• NERC SMS is seeking final PC approval of Phase Angle Monitoring

Technical Report.

Background


• The recommendations listed below are based on the assessment of phase angle monitoring, limit calculation, and alarming techniques. While the report focuses on practices in the Western Interconnection following the Pacific Southwest Outage, it was determined that these recommendations apply to all interconnections and entities performing the respective functions. The concepts of phase angle monitoring and alarming using both SCADA-based and time synchronized measurements for improved situational awareness apply to any Bulk-Power System.

RevisionsRecommendations Header Paragraph


• The contingency risk of interest is the outage of a transmission circuit and the phase angle difference across the out-of-service terminals of that line exceeding synchrocheck relay limits. This contingency and the pPost-contingency angle differences should be monitored in real-time. The Planning Coordinator and/or Reliability Coordinator should identify key transmission circuits for which this monitoring is required. It is recommended that awareness of synchrocheck relay limit exceedances be provided to system operators for EHV transmission circuits, where applicable, with nominal voltage greater than or equal to 345 kV.

Revisions:Recommendation #1

*NOTE: Recommendations 1 and 2 combined to avoid redundancy and to simplify.


• Phase angle differences for potential contingency conditions should be monitored in real-time and compared against synchrocheck relay settings, if applicable, for all EHV transmission circuits using Real-Time Contingency Analysis (RTCA) tools. Any N-1 or credible N-2 or N-1-1 exceedances of these limits should be provided to the system operator for advanced notice of potential line restoration issues.


*NOTE: No Changes Made.


• Wide-area phase angle difference monitoring provides an additional layer of situational awareness for system operators, and wide-area limits based on known risks such as transient stability, voltage stability, small signal stability, or overloads can effectively be developed based on operations studies or advanced online applications. Utilities should consider extracting phase angle difference values during system studies for stability risks, in conjunction with conventional MW flow limits.




• Line-based phase angle difference monitoring and comparison against known synchrocheck limits is not presently a universally adopted operating practice. It is recommended that the NERC Synchronized Measurement Subcommittee (SMS), in coordination with the NERC Operating Committee (OC), explore how this practice could be used or more widely adopted by the industry.

Complete revision from…• Current industry standards do not explicitly require line-based phase angle

difference monitoring and comparison to known synchrocheck limits. Applicable NERC Reliability Standards should consider requiring real-time monitoring of phase angles and synchrocheck limit violations as a mandatory practice for Reliability Coordinators (RCs) and Transmission Operators (TOPs).



• In the Western Interconnection, phase angle difference is correlated to oscillatory stability issues particularly during high transfer conditions. Tools such as Mode Meter, Oscillation Detection, and Phase Angle Difference (PAD) tools provide advanced analytical capabilities to detect any oscillatory issues linked with phase angle stress. It is recommended that utilities continue pursuing advancements in these tools for further situational awareness.




• Presented the revised (from PC reviewers) recommendations and an overview of the technical report materials to the NERC Operating Reliability Subcommittee (ORS) General discussion of findings, takeaways and recommendations

• ORS agreed with the practice of monitoring phase angle differences exceeding synchrocheck relay settings in both pre-and post-contingency conditions

• No changes requested on the recommendations• General consensus of endorsement – not put to formal vote

NERC ORS Engagement


Essential Reliability ServicesERSWG and DERTF

Brian Evans-Mongeon, ERSWG Co-ChairPlanning Committee MeetingsJune 7-8, 2016


2016 and 2017 Deliverables

2016 Deliverables:• Assist in process development for

approved measures• Whitepaper on methodology for

Essential Reliability Services (ERS) Measures Sufficiency Guidelines

• Final Report on Distributed Energy Resources

2017 Deliverable:• Final Report on ERS Measure Sufficiency

Guidelines


• Frequency Support Sufficiency Guidelines – In progress Data Gathering for Measures 1-4 with Resources Subcommittee – In

progress

• Voltage Support Sufficiency Guidelines – In progress System Analysis and Modeling Subcommittee – Reactive Power Guideline

Revision Monitoring of Measure 7 with the Performance Analysis Subcommittee

(PAS) – Given priority work with the State of Reliability, PAS has not yet had time to work on Measure 7

• Ramping Needs ERS formed a new subgroup for screening of ramping concerns – Reliability

Assessment Subcommittee Subgroup will also develop Sufficiency Guidelines

Essential Reliability Services Working Group


• Several conference calls and face-to-face meetings• Support from various industry experts• Draft report started Definition Modeling Operating Characteristics Review applicable NERC standards One immediate consideration: “Load Netting is BAD”

• DER Workshop with help from UVIG – In progress

Distributed Energy ResourcesTask Force


• ERSWG and DERTF continue to work on their end-of-year deliverables Meeting following the Standing Committees is here in St. Louis Workshop/Forum Another face-to-face meeting in Early August

• Monitoring of activities with other groups in progress Outreach to regulators for more involvement Still following IEEE 1547 FERC directives and initiatives

Next Steps


Distributed Energy Resources Task Force (DERTF)

Planning Committee MeetingBrian Evans-Mongeon, ERSWG Co-Chairman June 8, 2016


DERTF History

• The Task Force was formed in December 2015 under the umbrella of both Operating and Planning Committees (OC and PC)

• Task Force under the newly formed Essential Reliability Services Work Group

• DERTF Scope listed eight tasks• Finished product is a report approved by OC and PC and

submitted to BOT in December 2016• Membership is a representative of technical, renewable

developers, regulatory, and utility perspectives


• DERs in to planning models and studies• Operational impacts in areas with high penetration of non-

controllable resources • Facilitate data collection efforts and propose recommendations

for improved data collection efforts in NERC• Identify and recommend potential reliability metrics• Recommendation for consistently modeling and assessing DER• Review existing NERC Reliability Standards and coordinate with

IEEE 1547 related efforts• Review the NERC Functional Model between each category and

or treatment within NERC.• Consider development of Reliability Guideline and/or SAR

Eight DERTF Scope Tasks


ERSTF Work Plan

• Structure report outline to meet Scope requirements• Form groups of Subject Matter Experts to work each section

1. Definition of Distributed Energy Resources (DER) in context of report2. Typical electrical connections of DER3. Modeling of DER4. DER operating characteristics5. DER effects on the Bulk Electric System (BES)6. Applicable NERC Reliability Standards7. Recommendations

• Pull sections together into final report


• Draft report contains Sections 1, 2, and 3• Progressing on Sections 4, 5, and 6• Next meeting of ERSWG/DERTF is 6/8-6/9• Plans for a DERTF workshop 8/2-8/3

DERTF Progress


Impact of Device Protection & Control on Reactive Generator Effectiveness

David Till, Sr. Manager, Performance AnalysisPlanning Committee MeetingJune 7-8, 2016


Introduction

• The PC is requested to add a technical reference on Reactive Generator protection & controls to the System Protection and Controls Subcommittee (SPCS) 2016 work plan. No other PC Subgroups are identified at this time.

• Bulk power system (BPS) penetration of dedicated reactive generators (FACTS, synchronous condensers) will likely increase significantly should dynamic voltage support from conventional resources be lost to their retirement.

• Reactive generator protective systems must reliably coordinate with those of other BPS elements for this scenario.


STATCOM Serial #1 Station Service – Still a Common Achilles Heel?(Illustrative Non-P&C Issue Preventing Reliable Operation)

Station 500 kV Bank (1. Loss of 500 Bank is the Event that Threatens Area Voltage Collapse)

STATIC

SWITCHSTATCOMFACTS DEVICE

161-kV13-kV

480V

13-kV

161 kV

69 kV

Station 161 kV Bus

Distr. Sub 1

Primary SS (2. Primary SS unavailable when 500 kV bank trips)

Secondary SS (3. Secondary SS is subset of Primary SS)

Distr. Sub 2

13 kV

(4. STATCOM Supports 161 kV Bus voltage, but trips on loss of 480 V cooling pumps & control logic for any blip in SS, which occurs EVERY TIME the STATCOM is needed to mitigate voltage collapse!)


Conclusion

• Intentional and comprehensive discussion on requirements for reliable device operation includes a strong P&C component for which only SPCS holds expertise, as well as broad understanding of other topics with which SPCS is familiar.

Request the PC assign a technical reference regarding this issue to the SPCS Work Plan


Functional Model Advisory Group Update to the Planning Committee

Jerry Rust (FMAG co-chair) and Lacey Ourso (NERC staff)Planning Committee MeetingJune 7-8, 2016


Agenda

• Update regarding Functional Model Advisory Group (FMAG) 2016 project

• Discuss proposed revisions to the Functional Model (FM)• Obtain feedback from members of the Planning Committee

regarding proposed revisions


Background Information

• Purpose of the Functional Model (FM): (1) provide a framework for development of Reliability Standards, and (2) describe each function and relationships between entities responsible for

performing tasks required for each function.

• Purpose of the FMAG: (1) maintain the FM to ensure the model correctly reflects the industry

today, and (2) evaluate and incorporate new and emergent reliability-related tasks

• Revisions to the FM: “The FMAG reports to the full SC and consults with and submits all revisions to the Functional Model and its associated Technical Document to the NERC Critical Infrastructure Protection Committee (CIPC), Operating Committee (OC), and Planning Committee (PC) for endorsement.”


2016 FMAG project

• Current version of the FM developed in 2009 and approved by the NERC Board in 2010.

• Focus of 2016 effort: FMAG asked to review recent NERC initiatives (Risk-Based Registration

initiative) and standard development projects (Alignment of Terms) to identify any changes or updates to the FM language

Identify other changes needed as a result of new and emergent reliability-related issues


Project Timeline

• January 19-20: FMAG meeting to identify areas for focus • March 8: Inform committees (OC, PC, CIPC) of work underway,

and obtain initial feedback (specific to area of expertise) • March 17-18: FMAG meeting to develop revisions to the FM• April 13-15: FMAG meeting to develop revisions to FM and FMTD • June 7-8: Present proposed revisions to committee members (OC,

PC, CIPC) for the purpose of obtaining feedback • June 15-17: FMAG meeting to review and incorporate feedback

from committees (OC, PC, and CIPC), and revise FM and FMTD. • July/August: Post proposed revisions to FM and FMTD for

industry comment • September 13: Present final revisions to the FM and FMTD to

committees (OC, PC, and CIPC) for endorsement


Proposed Revisions to the FM

• High-level overview of proposed revisions to the FM: Incorporated Glossary terms Consolidated ERO-related functions (Reliability Assurer function) Clarified planning functions (PC, TP and RP) Added cyber and physical security tasks (RC, BA, TOP, TO, IC, DP, GO

and GOP) Added TOP task related to performing switching operations Revised tasks to clearly identify what actions are required for an

Interchange transaction (IC, BA, TSP, PSE, and LSE) Clarified TSP task of acquiring Ancillary Services Clarified DP task includes delivery to end-use customer or distribution-

connected energy resource(s)


Comments and Feedback

• Discuss comments and feedback of Planning Committee members regarding proposed revisions…


Contact information

• Jim Cyrulewski (co-chair)[email protected]

• Jerry Rust (co-chair)[email protected]

• Lacey Ourso (NERC staff)[email protected]




Potential Reliability Impacts of EPA’s Clean Power Plan Phase II

John Moura, Director, Reliability Assessment and System AnalysisPlanning Committee MeetingJune 7-8, 2016


Potential Reliability Impacts

• Developed through collaboration with stakeholders to inform policy discussions and highlight potential risks to BPS reliability

• Provides range of resource adequacy evaluations based on several potential cases using different models

• Provides framework for more granular studies at the state and regional level


• Formed to advise NERC on assessment scope and goals• Representation

All NERC Regions ISO\RTOs and Planning Coordinators IPPs and Renewable Energy Producers Trade Organizations Power Marketers Consultants Canadian Representation

• Sub-group formed to author the recommendations document• Work with modelers to develop scenarios and assumptions

Planning Committee Advisory Group


CPP Carbon Reduction Requirements

Acceleration of fundamental change in the electricity generation mix in the United States and transformation of reliability services, diversity, and flexibility


Scenarios


Expected Coal Capacity Decline

Coal capacity decline by up to 27 GWs


Large Amount ofRenewable Integration

Tax credits and renewable portfolio standards drive renewables

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20

40

60

80

100

120

140

160

180

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

Wind Solar

GW

Reference Case

CPP Base Case


Demand Growth

Annual energy demand growth is expected to flatten


Trading Case - Generation

Trading allowances provide market flexibility


Planning

Planning should already be under way due to the need for new transmission and natural gas pipeline infrastructure


Additional Areas for Analysis

• Operational dispatch and environmental constraints • Essential Reliability Services - Sufficiency Guidelines• Distributed Energy Resources Task Force• Increasing reliance on natural gas• Interconnection-wide studies• Regional/ISO/RTO studies


Federal and State Efforts in Ensuring Reliability

• EPA, DOE, FERC Memorandum of Understanding

• NERC’s identification of reliability considerations in Reliability Considerations for Clean Power Plan Development


Documents

Planning Committee Charter Update Highlights and...Probabilistic Assessment Guidelines document. • NERC-Regional Coordinated Special Assessment Expand the probabilistic study efforts