Agenda Operating Committee - NERC...Agenda – Operating Committee – March 5-6, 2019 3 c. Inverter-based Resource Performance Task Force – Al Schriver, Chair IRPTF d. E-ISAC Update

Agenda Operating Committee **Joint Session: Operating Committee (OC)/Planning Committee (PC)/ Critical Infrastructure Protection Committee (CIPC): March 5, 2019 | 10:00 a.m. – Noon Eastern March 5, 2019 | 1:00 – 5:00 p.m. EST March 6, 2019 | 8:00 a.m. – Noon EST Hyatt Regency Pittsburgh International Airport 1111 Airport Blvd Pittsburgh, PA 15231

Call to Order NERC Antitrust Compliance Guidelines and Public Announcement Introduction and Chair’s Remarks

1. Administrative items

a. Arrangements

i. Safety Briefing and Identification of Exits (Hotel Staff)

b. Announcement of Quorum

c. Background Information

d. OC Membership 2018-2020*

i. OC Roster*

ii. 30T32T32T30TUUOC Organizational Chart UU30T30T32T32T

iii. 30T32T32T30TOC Charter30T30T32T32T

iv. Parliamentary Procedures*

v. Participant Conduct Policy 30T30T32T32T

e. Future Meetings

i. Please note that Joint OC/PC/CIPC meetings will be scheduled from 10:00 a.m. to Noon on the first day of the Committee meetings.

2019 Meeting Dates Time Location Hotel

June 4, 2019 June 5, 2019

1:00 to 5:00 p.m. 8:00 a.m. to Noon

TBD TBD

http://www.nerc.com/comm/OC/Related%20Files%20DL/OC_Org_chart_20170830.pdf

http://www.nerc.com/comm/OC/Related%20Files%20DL/OC_Charter_20170930.pdf

http://www.nerc.com/comm/OC/Related%20Files%20DL/Final_NERC_Committee_Participant_Conduct_Policy_Approved.pdf

Agenda – Operating Committee – March 5-6, 2019 2

2019 Meeting Dates Time Location Hotel

September 10, 2019 September 11, 2019

1:00 to 5:00 p.m. 8:00 a.m. to Noon

TBD TBD

December 10, 2019 December 11, 2019

1:00 to 5:00 p.m. 8:00 a.m. to Noon

Atlanta, GA Intercontinental

Buckhead Consent Agenda – Approve

2. Minutes*

a. December 11-12, 2018 Meeting

Regular Agenda

3. Remarks and Reports

a. Remarks by Lloyd Linke, Operating Committee (OC) Chair

b. Report of February 6, 2019 Member Representatives Committee (MRC) Meeting and the February 7, 2019 Board of Trustees (Board) Meeting

c. Stakeholder Engagement – Efficiency and Effectiveness Review

d. Appointing additional Nominating Committee members

e. Annual Review of OC Organization*

4. 2019 OC Work Plan* – Approve - Chair Linke

a. 2018 Final OC Work Plan* - Information

5. OC Action Items Review* - Information – Vice Chair Zwergel

6. Subcommittee Status Reports - Information

a. Operating Reliability Subcommittee (ORS)* – Chair David Devereaux

i. MISO Reliability Plan*

ii. CAISO Reliability Plan*

b. Resources Subcommittee (RS)* – Chair Tom Pruitt

i. BAL-002 SAR recommendation

c. Event Analysis Subcommittee (EAS)* – Chair Rich Hydzik

d. Personnel Subcommittee (PS)* – Chair Rocky Williamson

e. Reliability Assessment Subcommittee (RAS)* – Chair Tim Fryfogle

7. Joint Meeting Topic Discussion – Review and Discussion – Chair Linke

a. Remarks – Rich Riazzi, Duquesne

b. Stakeholder Engagement Team, Effectiveness and Efficiency Initiative – Mark Lauby, NERC

Agenda – Operating Committee – March 5-6, 2019 3

c. Inverter-based Resource Performance Task Force – Al Schriver, Chair IRPTF

d. E-ISAC Update – Sam Chanoski, E-ISAC

8. Reliability Issues Steering Committee (RISC) Status Report – Information – Vice Chair Zwergel

9. Lessons Learned – Coordinating with First Responders – Anthony Natale, Emergency Preparedness, Consolidated Edison, NY

10. SAFNR Update – Darrell Moore, NERC Staff

11. Parallel Flow Visualization – Dave Devereaux, ORS Chair

12. Blackstart Cranking Path – David Rode, Southern California Edison

13. Overview of Frequency Oscillation Event January 11, 2019 – Tim Fritch, TVA

14. Project 2015-09 Establish and Communicate System Operating Limits; Review of SOL Standards – Hari Singh, Vice Chair

15. Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard* – Information – Rich Hydzik, Vice Chair, Project 2017-01 Modifications to BAL-003-1.1 Standard Drafting Team

16. Southern Company – Super Bowl after action review – Mike Robinson, Southern Company

17. OC Reliability Guideline and Reference Document Quick Reference Guide* – Information – Stephen Crutchfield, NERC Staff

18. Task Force Updates

a. Real-time Assessments Quality Task Force (RTAQTF) Guidance – Information – Doug Peterchuck, RTAQTF Chair

b. Inverter-based Resources Performance Task Force (IRPTF) – Information – Allen Schriver, IRPTF Chair

19. WECC Reliability Coordinator Updates– Information

a. WECC – James Hanson

b. California ISO – Eric Schmitt

c. SPP RC – CJ Brown, SPP

20. Forum and Group Reports - Information

a. North American Generator Forum – Allen Schriver

b. North American Transmission Forum* – Ed Ernst

21. Standards Update – Howard Gugel, NERC

22. Chair’s Closing Remarks

23. Adjournment

*Background materials included.

NERC Antitrust Compliance Guidelines I. General

It is NERC’s policy and practice to obey the antitrust laws and to avoid all conduct that unreasonably restrains competition. This policy requires the avoidance of any conduct that violates, or that might appear to violate, the antitrust laws. Among other things, the antitrust laws forbid any agreement between or among competitors regarding prices, availability of service, product design, terms of sale, division of markets, allocation of customers or any other activity that unreasonably restrains competition. It is the responsibility of every NERC participant and employee who may in any way affect NERC’s compliance with the antitrust laws to carry out this commitment. Antitrust laws are complex and subject to court interpretation that can vary over time and from one court to another. The purpose of these guidelines is to alert NERC participants and employees to potential antitrust problems and to set forth policies to be followed with respect to activities that may involve antitrust considerations. In some instances, the NERC policy contained in these guidelines is stricter than the applicable antitrust laws. Any NERC participant or employee who is uncertain about the legal ramifications of a particular course of conduct or who has doubts or concerns about whether NERC’s antitrust compliance policy is implicated in any situation should consult NERC’s General Counsel immediately.

II. Prohibited Activities

Participants in NERC activities (including those of its committees and subgroups) should refrain from the following when acting in their capacity as participants in NERC activities (e.g., at NERC meetings, conference calls and in informal discussions):

Discussions involving pricing information, especially margin (profit) and internal cost information and participants’ expectations as to their future prices or internal costs.

Discussions of a participant’s marketing strategies.

Discussions regarding how customers and geographical areas are to be divided among competitors.

Discussions concerning the exclusion of competitors from markets.

Discussions concerning boycotting or group refusals to deal with competitors, vendors or suppliers.

Any other matters that do not clearly fall within these guidelines should be reviewed with NERC’s General Counsel before being discussed.

III. Activities That Are Permitted

From time to time decisions or actions of NERC (including those of its committees and subgroups) may have a negative impact on particular entities and thus in that sense adversely impact competition.

NERC Antitrust Compliance Guidelines 2

Decisions and actions by NERC (including its committees and subgroups) should only be undertaken for the purpose of promoting and maintaining the reliability and adequacy of the bulk power system. If you do not have a legitimate purpose consistent with this objective for discussing a matter, please refrain from discussing the matter during NERC meetings and in other NERC-related communications. You should also ensure that NERC procedures, including those set forth in NERC’s Certificate of Incorporation, Bylaws, and Rules of Procedure are followed in conducting NERC business. In addition, all discussions in NERC meetings and other NERC-related communications should be within the scope of the mandate for or assignment to the particular NERC committee or subgroup, as well as within the scope of the published agenda for the meeting. No decisions should be made nor any actions taken in NERC activities for the purpose of giving an industry participant or group of participants a competitive advantage over other participants. In particular, decisions with respect to setting, revising, or assessing compliance with NERC reliability standards should not be influenced by anti-competitive motivations. Subject to the foregoing restrictions, participants in NERC activities may discuss:

Reliability matters relating to the bulk power system, including operation and planning matters such as establishing or revising reliability standards, special operating procedures, operating transfer capabilities, and plans for new facilities.

Matters relating to the impact of reliability standards for the bulk power system on electricity markets, and the impact of electricity market operations on the reliability of the bulk power system.

Proposed filings or other communications with state or federal regulatory authorities or other governmental entities.

Matters relating to the internal governance, management and operation of NERC, such as nominations for vacant committee positions, budgeting and assessments, and employment matters; and procedural matters such as planning and scheduling meetings.

Public Meeting Notice REMINDER FOR USE AT BEGINNING OF MEETINGS AND CONFERENCE CALLS THAT HAVE BEEN PUBLICLY NOTICED AND ARE OPEN TO THE PUBLIC Conference call/webinar version: As a reminder to all participants, this webinar is public. The registration information was posted on the NERC website and widely distributed. Speakers on the call should keep in mind that the listening audience may include members of the press and representatives of various governmental authorities, in addition to the expected participation by industry stakeholders. Face-to-face meeting version: As a reminder to all participants, this meeting is public. Notice of the meeting was posted on the NERC website and widely distributed. Participants should keep in mind that the audience may include members of the press and representatives of various governmental authorities, in addition to the expected participation by industry stakeholders. For face-to-face meeting, with dial-in capability: As a reminder to all participants, this meeting is public. Notice of the meeting was posted on the NERC website and widely distributed. The notice included the number for dial-in participation. Participants should keep in mind that the audience may include members of the press and representatives of various governmental authorities, in addition to the expected participation by industry stakeholders. August 10, 2010

- 1 -

Parliamentary Procedures Based on Robert’s Rules of Order, Newly Revised, 1990 Edition

Motions Unless noted otherwise, all procedures require a “second” to enable discussion.

When you want to… Procedure Debatable Comments Raise an issue for discussion

Move Yes The main action that begins a debate.

Revise a Motion currently under discussion

Amend Yes Takes precedence over discussion of main motion. Motions to amend an amendment are allowed, but not any further. The amendment must be germane to the main motion, and cannot reverse the intent of the main motion.

Reconsider a Motion already approved

Reconsider Yes Allowed only by member who voted on the prevailing side of the original motion.

End debate Call for the Question or End Debate

No If the Chair senses that the committee is ready to vote, he may say “if there are no objections, we will now vote on the Motion.” Otherwise, this motion is debatable and subject to 2/3 majority approval.

Record each member’s vote on a Motion

Request a Roll Call Vote

No Takes precedence over main motion. No debaterequired, but the members must approve by 2/3 majority.

Postpone discussion until later in the meeting

Lay on the Table Yes Takes precedence over main motion. Used only topostpone discussion until later in the meeting.

Postpone discussion until a future date

Postpone until Yes Takes precedence over main motion. Debatable only regarding the date (and time) at which to bringthe Motion back for further discussion.

Remove the motion for any further consideration

Postpone indefinitely

Yes Takes precedence over main motion. Debate can extend to the discussion of the main motion. If approved, it effectively “kills” the motion. Useful for disposing of a badly chosen motion that cannot be adopted or rejected without undesirable consequences.

Request a review of procedure

Point of order No Second not required. The Chair or secretary shall review the parliamentary procedure used during the discussion of the Motion.

Notes on Motions Seconds. A Motion must have a second to ensure that at least two members wish to discuss the issue. The “seconder” is not recorded in the minutes. Neither are motions that do not receive a second. Announcement by the Chair. The Chair should announce the Motion before debate begins. This ensuresthat the wording is understood by the membership. Once the Motion is announced and seconded, the Committee “owns” the motion, and must deal with it according to parliamentary procedure.

Revisions. Technically, revisions to the main motion are accomplished by the Amend procedure. However, immediately after making the motion, and before it is announced by the Chair, another member may ask that the motion be revised. If the original “motion -maker” agrees to the revision, then the revised motion will be the one debated. The original “seconder” need not be consulted, because the original “motion-maker” plus the “reviser” constitute a motion and a second.

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Operating CommitteeOrganizational Chart

March 2019

RELIABILITY | ACCOUNTABILITY2

NERC Operating Committee (OC)

Reserves Working Group (RWG)

Operating Committee Executive Committee (OC ExCom)

Continuing Education Review Panel (CERP)

Events Analysis Subcommittee

(EAS)

Inverter-Based Resource

Performance Task Force (IRPTF)

Eastern Interconnect Data Sharing Network

(EIDSN)

Energy Management Systems Working

Group (EMSWG)

Joint OC/PC Task Forces

Resources Subcommittee (RS)

Personnel Subcommittee (PS)

Operating Reliability

Subcommittee (ORS)

Frequency Working Group (FWG)

Inadvertent Interchange Working

Group (IIWG)

Current Organizational Chart


**Joint OC/PC Task Force or Working Group

Subgroup Leadership & NERC Staff Support – March 2019

OC Subgroup Chair Vice Chair NERC Support

Personnel Subcommittee (PS) Rocky Williamson Leslie Sink Trion King

Continuing Education Review Panel (CERP) Rocky Williamson Leslie Sink Trion King

Resources Subcommittee (RS) Tom Pruitt Sandip Sharma Brad Gordon / Elsa Prince

Reserves Working Group (RWG) Tony Nguyen Vacant Brad Gordon / Elsa Prince

Frequency Working Group (FWG) Danielle Croop Vacant Brad Gordon / Elsa Prince

Inadvertent Interchange Working Group (IIWG) Bill Hanson Vacant Brad Gordon / Elsa Prince

Operating Reliability Subcommittee (ORS) David Devereaux Chris Pilong Darrell Moore

Eastern Interconnect Data Sharing Network (EIDSN) Don Reichenbach Chris Wakefield Darrell Moore

Events Analysis Subcommittee (EAS) Rich Hydzik Vinit Gupta Jule Tate

EMS Working Group (EMSWG) Venkat Tirupati Phil Hoffer Wei Qiu

Inverter-Based Resource Performance Task Force (IRPTF)** Al Schriver Jeff Billo Ryan Quint

*** Joint OC/PC group

Agenda Item XX

March 5-6, 2019 OC Meeting

Description Status Due Notes

Reliability Guidelines:

Reliability Guideline: Primary Frequency Control and summary

documentIn Progress Q4 2018

RS; authorizated 45-day posting December 2018. Will

be carry-over item for 2019.

Integrating Reporting ACE with the NERC Reliability Standards and

summary documentIn Progress Q4 2019

RS

Situational Awareness for the System Operator and summary


PS; note early 2020 due date. Work should begin in

2019

Generating Unit Winter Weather Readiness – Current Industry

Practices and summary documentIn Progress Q3 2019

EAS

Reference Documents:

NERC Balancing and Frequency Control Technical Document and

summary document

In Progress Q2 2019

RS has reviewed and determined whether to this

document should be updated. Some, but not all, the

topics are addressed in other reference documents.

For those topics covered in other documents, this

document will cover the topic briefly but have

references to the other documents for in-depth

detail.

Time Monitoring Reference Document and summary document In Progress Q3 2019 RS/ORS

Geomagnetic Disturbance Monitoring Reference Document and

summary documentIn Progress Q3 2019

ORS

Dynamic Transfer Reference Document and summary document In Progress Q2 2019ORS

Balancing Authority Area Footprint Change Tasks and summary


RS; Posted for comment through Feb 18, 2019.

Review and update Dynamic Transfer Reference Document;

Dynamic Tag Exclusion Reference Document; Pseudo-Tie

Coordination Reference Document and summary document

In Progress Q4 2019

ORS to take lead to combine these three into a single

Ref Doc as part of 2019 Work Plan. Coordinate with

RS.

Compliance Implementation Guidance development:

Draft Compliance Implementation Guidance the NERC Data

Exchange Infrastructure Requirements Task Force developed for

TOP-001-4 R20, R21, R23, R24 and IRO-002-5 R2 and R3

In progress Q4 2019

EAS is developing this guidance.

RTAQTF Guidance In progress Q4 2019

General Topics (may be annual items):

Nominating Committee to present slate for OC Chair and Vice-

Chair at June meeting for election.Every two years or as

necessaryQ2 2019

2019 Task; Announce at March OC meeting

Annual membership nomination period and election if necessary.

Annually Q3

Announce at June meeting and hold nomination

period immediately after for August BOT

appointment.

OC Chair Appointment of Subcommittee Leadership after

appointment of a new OC chair.Every two years or as

necessaryQ4 2019

2019 Task; Subcommittees should be prepared to

make recommendations for Chair and Vice Chair prior

to December 2019 OC meeting.

OC Structure and organization. Per Section 6.1 of OC Charter, the

OC will "annually review the appropriateness of ongoing

subcommittees, task forces, and working groups"

Review in Q1, OC

EXCOM planning

meeting

Q1 2019 Performed at January 17, 2019 meeting

OC review of Time and GMD Monitor transitions In Progress Q1 2019 ORS to report to OC in March

OC review of its Strategic Plan

Every two years or as

necessary. Q2 2020

Solicit volunteers at September or December 2019

meeting pending outcome of Efficiency and

Effectiveness review. Review to ensure that the OC

plan is in sync with the updated ERO strategic plan

with OC approval Q2 2020.Development of OC and subcommittee work plans. Monitor RISC

report, Resiliency Framework, ERO Strategic Plan and other

documents as it relates to possible OC actions.

In Progress Q1 2019

Complete January 17, 2019. Modify as needed.

OC Work PlanOriginal January 17, 2019

Review and approval of the Annual Frequency Response Analysis

Report during Q4 of each year.In Progress Q4 2019

NERC Staff develops the FRAA and the RS reviews and

makes a recommendation to OC for approval.NERC Website: Per OC Strategic plan, Reliability Guidelines,

Reference Documents and Lessons Learned will be grouped

together based on focus area

In Progress Q4 2019

Per OC Strategic Plan: Engage the Regional Entity by volunteering

to present new reliability guideline and reference documents and

updated guidelines and reference documents

In Progress Q4 2019

Identify reliability guidelines and reference documents that are

under development and revision at the joint OC/PC/CIPC meetings

In Progress on-going

Coordinate with SCGC to have this as a standing

agenda item for the Joint Meeting.

Provide support for Inverter-based Resource Performance Task

Force (Joint OC/PC TF).In Progress Q4 2019

OC will coordinate presentations at the June 2019 Joint

OC/PC/CIPC meeting regarding implementation of DER and impact

on forecasting, etc.

In Progress Q2 2019

OC will facilitate having a presentation on SCE cranking path

experience at March 2019 OC meetingIn Progress Q1 2019

James Merlo to coordinate with SCE.

Events Analysis Program Review and Update In Progress Q2 2019 3 year review periodicity or as needed.

CE Manual 5.0 approval In Progress Q3 2019

Description Status Due

CE Program Manual 5.0 In progress

Revise audit requirements In progress Q1_2019

Revise administrative requirements In progress Q1_2019

Construct guidelines (Provider/Course) In progress Q1_2019

Review and approval process (Tech Pub and OC) Q2_2019 Q3_2019

Edit and finalize Q3_2019 Q1_2020

Implement Change Management Plan Q4_2019 Q1_2020

Release CE Program Manual 5.0 Q1_2020 Q1_2020

Monitor and assess CE Program Manual 5.0*

Industry survey Q2_2020 Q3_2020

Evaluate Q3_2020 Q4_2020

Define scope (5.1) Q4_2020 Q1_2021Reliability Guidelines and Reference Documents - Develop

summary for each document and conduct webinars as needed for

each revised document.


Review and coordinate with PCGC regarding survey of certification

credentials results.In progress Q4 2018

Situational Awareness for the System Operator In Progress Q1 2020PS; note early 2020 due date. Work should begin in

2019. ORS to assist.

Review and Update PS Scope document In progress Q3 2019

Conduct Level 2 course audits and provider audits In progress on-going

PS Work PlanOriginal January 17, 2019


Review and vet the Frequency Bias Settings and L10 values;

scheduled to be implemented in April of each year. Repeated

annual in accordance with the BAL-003-1 standard.

Ongoing Q2 Yearly

Ongoing support of Planning Committee’s Performance Analysis

Subcommittee metric M4, Interconnection Frequency Response

for the annual State of Reliability Report

Ongoing Quarterly

Review and approval of the Annual Frequency Response Analysis

Report during Q4 of each year.

In Progress - NERC

Staff Task, RS

approval, OC

Endorsement

Q4

NERC Staff develops the FRAA and the RS reviews and

makes a recommendation to OC for approval.

Quarterly review of BA’s control performance. Ongoing Quarterly

Resolve DCS Data Reporting with NERC and Standard Drafting

Teams in lieu of proposed changes with standards. In Progress

Review

quarterly

The reporting methodology and applicable forms

has been completed. The OC letter requesting

voluntary submittal of quarterly DCS data via the

BAS Site needs to be distributed. The RS will

review this data quarterly ad infinitum.

Annual review of CERTS/NERC (fnet, etc.) real-time applications.Annually Q3

Generator Survey for Eastern, Western, and HQ Interconnections

In Progress Q4 2018

Approximately two events selected each year for the

upcoming years. Conduct Webinars to identify issues

and support industry.

Inadvertent Interchange Accounting Training Document. Annually Q3 2018

Support the ERSWG Measures 1, 2, 4, and 6 as much a practicably

possible and the full implementation of BAL-003-1.

In Progress Q4 2019

Support of the existing measures is already in place

and ongoing (each measure is reviewed for each

interconnection at each RS meeting).

A sub-team has been established (led by Brad

Gordon) to modify/develop ERS sub-measures and

improved metrics. The due date is Q4 2019 for this

effort.

Development of a Change in BA Footprint Reference Document In Progress Q1 2019 Posted for Comment through February 18, 2019

Develop document for annual review and recommendations for

changes in Frequency Bias SettingsIn Progress Q4 2019

Support the efforts of the BAL-003-1 SDT


BAL-003-1 Implementation Support, which was

complete with the full implementation of the

standard in March 2018. This includes changes to the

annual frequency bias and L10 setting which details

BA’s frequency bias values and FROs-Frequency

Response Obligations.

Support the efforts of the BAL-003 SDT In Progress on-going

Reliability Guidelines and Reference Documents - Develop




NERC Balancing and Frequency Control Technical Document

In Progress Q2 2019

RS has reviewed and determined whether this

document should be updated. Some, but not all, the

topics are addressed in other reference documents.

For those topics covered in other documents, this

document will cover the topic briefly but have

references to the other documents for in-depth

detail.

Reliability Guideline: Primary Frequency Control In Progress Q4 2018RS; authorizated 45-day posting December 2018. Will

be carry-over item for 2019.

Integrating Reporting ACE with the NERC Reliability Standards In Progress Q4 2019 RS

Time Monitoring Reference Document In Progress Q3 2019 RS/ORS

RS Work PlanOriginal January 17, 2019



Coordination Reference Document

In Progress Q4 2019



RS.


Monitor development of common tools and act as point of contact

for EIDSN. In Progress Q1 2019

ORS to act as lead on development of, and recommendation to

implement, Parallel Flow Visualization tool.In Progress Q2 2019

Notify OC of Time Monitors for 2019 and 2020. In Progress Q1 2019 WI and EI

GridEx IV After Action Report Follow-on Work Q3 2019

Support GridEx V In Progress Q4 2019

Frequency Monitor Reporting (Standing ORS agenda item to

discuss). In Progress Q3 2019





Develop Reliability Guideline or Reference Document to improve

short-term and mid-term load forecasting (from RISC

Recommendation 7 under Risk #2).

In Progress Q1 2020

Time Monitoring Reference Document In Progress Q3 2019 RS/ORS

Geomagnetic Disturbance Monitoring Reference Document In Progress Q3 2019 ORS



Coordination Reference Document

In Progress Q4 2019



RS.

Monitor and reivew development of Western Interconnection RC

Reliability PlansIn Progress Q4 2019

ORS Work Plan

Original January 17, 2019


EAS industry presentation quarterly for OC meetings relating to

operational experiences and eventsContinuous Quarterly

Plans, arrangements and agenda for Annual Monitoring and

Situational Awareness ConferenceIn Progress Q3 Annually

Scheduled for September 24-25 at SPP

Prepare for and facilitate the Annual Winter Weather Prep

Webinar.In Progress Q3 annually

Scheduled for September 5, 2019 from 2-3pm ET

Analysis of cause codes looking for common threads and trends.

Provide annual update to OC on trends, threads, etc.As needed Q4 2018

Prepare for and facilitate lessons learned summary webinars. As needed As needed





Develop EA Chapter of the State of Reliability Report in

coordination with PASIn Progress Q4 2019

Annual update to the OC of events, cause codes, trends, etc. Annually Q3 Annually

Generating Unit Winter Weather Readiness – Current Industry

PracticesIn Progress Q3 2019

EAS

Risks and Mitigations for Losing EMS Functions Reference

DocumentIn Progress Q1 2020 EMSWG

Draft Compliance Implementation Guidance the NERC Data

Exchange Infrastructure Requirements Task Force developed for

TOP-001-4 R20, R21, R23, R24 and IRO-002-5 R2 and R3

In progress Q4 2019

EAS is developing this guidance.

Lessons Learned development and publication Continuous on-going

Events Analysis Program Review and Update In Progress Q2 2019 3 year review periodicity or as needed.

EAS Work PlanOriginal January 17, 2019

Agenda Item 4a

OC Meeting

March 5-6, 2019

Description Status Due Notes

Reliability Guidelines:

Loss of Real-Time Reliability Tools Capability/Loss of

Equipment Significantly Affecting ICCP Data

In Progress Q4 2018Retired by OC December 2018

Generating Unit Operations During Complete Loss of

Communications

In Progress Q2 2018Approved by OC December 2018

Reliability Guideline: Primary Frequency Control

In Progress Q4 2018RS; authorizated 45-day posting December 2018.

Will be carry-over item for 2019.

Reference Documents:

Reliability Coordinator Plan Reference Document In Progress Q2 2018 Approved by OC December 2018

NERC Balancing and Frequency Control Reference Document In Progress Q4 2018 RS reviewed and will update and plan to send to

OC in June.

General Topics (may be annual items):

OC Chair Appointment of Subcommittee Leadership after

appointment of a new OC chair.

Every two years or as

necessary

Q42019 Task

OC Structure and organization. Per Section 6.1 of OC Charter,

the OC will "annually review the appropriateness of ongoing

subcommittees, task forces, and working groups"

Review in Q1, OC

EXCOM planning

meeting

Q1 2018

Complete in Q1

OC review of Time and GMD Monitor transitions In Progress Q1 2018 ORS to report to OC in March. Complete.

OC review of its Strategic Plan As required. Solicit

volunteers at March

2018 meeting

Q3 2018 Review to ensure that the OC plan is in sync with

the updated ERO strategic plan. Complete


summary for each document and conduct webinars as needed

for each revised document.

In Progress on-going Each subcommittee will develop this as needed

for documents they revise.

Maintain awareness of Resiliency Framework development as

it relates to possible OC actions.In Progress on-going

Review and approval of the Annual Frequency Response

Analysis Report during Q4 of each year.

In Progress Q4 NERC Staff develops the FRAA and the RS reviews

and makes a recommendation to OC for approval.

Complete. Approved via email ballot November

16, 2018.Develop formal rollout process for new and updated

reliability guidelines and reference documentsIn Progress Q4 2018 Complete. Approived in September

NERC Website: Per OC Strategic plan, Reliability Guidelines,

Reference Documents and Lessons Learned will be grouped

together based on focus area

In Progress Q4 2018 On-going

Per OC Strategic Plan: Engage the Regional Entity by

volunteering to present new reliability guideline and

reference documents and updated guidelines and reference

documents

In Progress Q4 2018 On-going

Identify reliability guidelines and reference documents that

are under development and revision at the joint OC/PC/CIPC

meetings

In Progress Q4 2018 Coordinate with SCCG to have this as a standing

agenda item for the Joint Meeting. Ongoing.

Provide support for Real-time Assessments Task Force.In Progress on-going Complete. Guidance was approved by the ERO in

May, 2018.Provide support for Inverter-based Resource Performance

Task Force (Joint OC/PC TF).In Progress on-going Guideline approved at September OC meeting.

IRPTF will resume activities in January, 2019.Provide support for Methods for Establishing IROLs Joint Task

Force (Joint OC/PC TF).In Progress on-going Complete. Guideline, Framework approved at

September OC meeting. MEITF was disbanded..

OC Work PlanOriginal January 10, 2018


CE Program Manual 5.0 In progress

Define scope Completed Q1_2018

Revise course requirements Completed Q3_2018

Revise provider requirements In progress Q4_2018

Construct guidelines (Provider/Course) In progress Q1_2019

Revise audit requirements In progress Q1_2019

Revise administrative requirements In progress Q1_2019

Review and approval process (Tech Pub and OC) Q1_2019 Q3_2019

Edit and finalize Q3_2019 Q1_2020

Implement Change Management Plan Q4_2019 Q1_2020

Release CE Program Manual 5.0 Q1_2020 Q1_2020

Monitor and assess CE Program Manual 5.0*

Industry survey Q2_2020 Q3_2020

Evaluate Q3_2020 Q4_2020

Define scope (5.1) Q4_2020 Q1_2021Reliability Guidelines and Reference Documents - Develop


for each revised document.In Progress on-going

Review and coordinate with PCGC regarding survey of

certification credentials results.In progress Q4 2018

Conducting 1st quarter Audits of providers In progress Q2 2019

PS Work PlanOriginal January 10, 2018

Revised December 2018


Review and vet the Frequency Bias Settings and L10 values;

scheduled to be implemented in April of each year. Repeated

annual in accordance with the BAL-003-1 standard.

Ongoing Q2 Yearly

Complete for 2018

Ongoing support of Planning Committee’s Performance

Analysis Subcommittee metric M4, Interconnection Frequency

Response for the annual State of Reliability Report

Ongoing Quarterly

Review and update RS Scope In Progress Q3 2018 Approved by OC December 2018

Review and approval of the Annual Frequency Response

Analysis Report during Q4 of each year.

In Progress - NERC

Staff Task, Not RS

Q4 NERC Staff develops the FRAA and the RS reviews

and makes a recommendation to OC for approval.

Complete. Approved via email ballot November

16, 2018.

Quarterly review of BA’s control performance. Ongoing Quarterly

Resolve DCS Data Reporting with NERC and Standard Drafting

Teams in lieu of proposed changes with standards. In Progress

Review

quarterly

The reporting methodology and applicable

forms has been completed. The OC letter

requesting voluntary submittal of quarterly

DCS data via the BAS Site needs to be

distributed. The RS will review this data

quarterly ad infinitum.

Annual review of CERTS/NERC (fnet, etc.) real-time

applications.

Annually Q3Complete

Eastern Interconnection Frequency Response Initiative/NERC

Advisory ”Generator Governor Frequency Response”; with the

continued leadership of Chair Troy Blalock work with NERC

and the ever expanding list of suppliers that provide governor

control equipment to inform/educate the industry on this

topic, with the goal of a voluntary effort that improves

Frequency Response throughout the interconnections. While

it was hope that this effort would be complete during 2015, it

appears that it may become an ongoing effort for a period of

time.

In Progress Q4 2018

Generation Survey for Eastern, Western and HQ

Interconnections. Approximately two events

selected each year for the upcoming years.

Conducted Webinars to identify issues and

support industry.

Inadvertent Interchange Accounting Training Document. Annually Q3 2018 reviewed but no update necessary

Support the ERSWG Measures 1, 2, 4, and 6 as much a

practicably possible and the full implementation of BAL-003-1.

In Progress Q4 2019 Support of the existing measures is already in

place and ongoing (each measure is reviewed for

each interconnection at each RS meeting).

A sub-team has been established (led by Brad

Gordon) to modify/develop ERS sub-measures

and improved metrics. The due date is Q4 2019

for this effort.

Development of a Change in BA Footprint Reference

DocumentIn Progress

Q4 2018Posted for Comment through February 18, 2019

Develop document for annual review and recommendations

for changes in Frequency Bias SettingsIn Progress

Q4 2019Closely tied to BAL-003-1 SDT.

Support the efforts of the BAL-003-1 SDT In Progress on-going BAL-003-1 Implementation Support, which was

complete with the full implementation of the

standard in March 2018. This includes changes to

the annual frequency bias and L10 setting which

details BA’s frequency bias values and FROs-

Frequency Response Obligations.

Support the efforts of the BAL-002-2 SDT In Progress on-going Complete

RS Work PlanOriginal January 10, 2018





Developed as docs are updated.

NERC Balancing and Frequency Control Reference Document In Progress Q2 2019 RS has reviewed and determined whether this

document should be updated. Some, but not all,

the topics are addressed in other reference

documents. For those topics covered in other

documents, this document will cover the topic

briefly but have references to the other

documents for in-depth detail.

Reliability Guideline: Loss of Real-Time Reliability Tools

Capability/Loss of Equipment Significantly Affecting ICCP Data

In Progress Q4 2018

Retired by OC December 2018

Reliability Guideline: Generating Unit Operations During

Complete Loss of Communications


Reliability Guideline: Primary Frequency Control In Progress Q4 2018 Posted for comment through Feb 18, 2019.


Monitor development of Net Actual / Net Scheduled

Interchange Tool (EIDSN)

In Progress Q2 2019

Notify OC of Time Monitor for 2018 and 2019. In Progress Q1 2018 Complete

GridEx IV After Action Report Follow-on Work Q3 2018 ORS coordinated with E-ISAC and expects to

continue work in 2019.

Support GridEx V In Progress Q4 2018 ORS coordinated with E-ISAC and expects to

continue work in 2019.

Develop a reference document for recognition of cyber

intrusions into operating systems in collaboration with CIPC.

(RISC report Risk Profile 9, mitigation item 10.)

In Progress Q2 2018 Complete

Review and update ORS Scope document In Progress Q3 2018 Approved by OC December 2018

Frequency Monitor Reporting (Standing ORS agenda item to

discuss).

In Progress Q3 2018

Reliability Coordinator Plan Reference Document In Progress Q2 2018 Approved by OC December 2018

Reliability Guideline: Loss of Real-time Reliability Tools


Reliability Guideline

In Progress Q1 2019






Improve short-term and mid-term load forecasting (from RISC

Recommendation 7 under Risk #2).In Progress Q4 2018

ORS is coordinating with RS. 2019 item. May need

to coordinate with PC.

Review ERSWG Metrics In Progress Complete. No scope changes.

ORS Work Plan

Original January 10, 2018


EAS industry presentation quarterly for OC meetings relating

to operational experiences and events

Continuous Quarterly March - Hurricane Harvey

June - Hurricane Irma

September - PJM Load Shed event

December – Drone Presentation

Review and update ESA Scope In Progress Q3 2018 OC approved the EAS Scope document v 1.2

September 11, 2018

Plans, arrangements and agenda for Annual Monitoring and

Situational Awareness Conference

In Progress Q3 Annually Scheduled for October 1-3 at MISO, Carmel. On

schedule for September 2019.

Prepare for and facilitate the Annual Winter Weather Prep

Webinar.

In Progress Q3 annuallyCompleted for September 6, 2018

Analysis of cause codes looking for common threads and

trends. Provide annual update to OC on trends, threads, etc.

As needed Q4 2018

Prepare for and facilitate lessons learned summary webinars. As needed As neededFebruary - Risks and Mitigations for Losing EMS

Function Reference Document Webinar

May - Loss of Solar Resources during Transmission

Disturbances due to Inverter Settings - II Webinar





Reliability Guideline: Loss of Real-Time Reliability Tools


In Progress Q4 2018


Reliability Guideline: Generating Unit Operations During

Complete Loss of Communications


Develop EA Chapter of the State of Reliability Report in

coordination with PASIn Progress Q4 2018

Annual update to the OC of events, cause codes, trends, etc.Annually Q3 Annually

EAS Work PlanOriginal January 10, 2018

NERC Operating Committee Action Items

Dated: January 18, 2019

NERC Operating Committee Action Items Page 1 of 2

March 2016 Meeting Action Items OC meeting

and item number

Assignment Description Due Date Progress Status

1603-06 Resources Subcommittee

(RS)

Modify the Reliability Guideline: Primary Frequency Control to address asynchronous resources

December 2018

March 2017 - The RS is developing a draft Reliability Guideline. March 2018 – The RS will be revising the Primary Frequency Control guideline in 2018 and will incorporated this into the revision. December - OC authorization to post for a 45-day comment period.

In Progress

March 2018 Meeting Action Items OC meeting

and item number


1803-05 EAS TOP-001-4, Requirements R20 and R21

September 2018

March 2018 - The EAS will review R20 and R21 as requested to clarify “redundant and diversely routed” language as well as testing requirements. June 2018 – The EAS is working to develop guidance for these requirements. December 2018 – The EAS provided a status update. The team is working to address issues and concerns raised by industry.

In Progress

1803-06 RTAQTF

TOP-010 and IRO-018 requirements about data quality

September 2018

March 2018 – The RTAQTF will develop documentation (Compliance Guidance or similar) to address RTA quality as identified in TOP-010, R3 and the associated IRO-018 requirement. December 2018 – The team continues to develop Implementation Guidance to address quality. The team is targeting the March 2019 OC meeting for approval.

In Progress

NERC Operating Committee Action Items

Dated: January 18, 2019

NERC Operating Committee Action Items Page 2 of 2

September 2018 Meeting Action Items OC meeting

and item number


1809-01 Resources Subcommittee

Technical assessment of the proposed BAL-002 SAR.

December 2018

September 2018 – Howard Gugel requested the OC provide input relating to the technical merits of a recently submitted SAR for revisions to Reliability Standard BAL-002. The NERC SC received a SAR from Arizona Public Service to modify Reliability Standard BAL-002-2(i) Disturbance Control Standard—Contingency Reserve for Recovery from a Balancing Contingency Event. Chair Linke assigned the review to the RS. The RS will review the SAR at their next meeting and will report back to the OC in December, if not before.

December 2018 - The RS reviewed the SAR at their October meeting and reported back the following: Standard Authorization Request for BAL-002-3: The Resources Subcommittee opinion on the soundness of the request is that the SAR should not go forward as written. The recommended modification of R1.1 of this standard to include interconnection frequency assessment will modify the original intent of standard, Meeting Minutes – Operating Committee Meeting – December 11-12, 2018 which is the demonstration of the deployment of reserves to recover from Reportable Balancing Contingency Events (RBCEs). However, the concerns raised in this SAR can be addressed by other means. Follow up action – The full OC will follow up with a discussion and resolution at the March, 2019 meeting with a report from the OC out to the NERC Standards Committee.

In Progress

Agenda Item 6a OC Meeting

March 5-6, 2019

NERC Operating Committee Sub-group Status Report

Group: Operating Reliability Subcommittee Purpose: The Operating Reliability Subcommittee (ORS) assists the NERC Operating Committee

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

Last Meeting: February 12-13, 2019 Location: Tampa FL (hosted by FRCC) Duration: 1 Day Next Meeting: May 7-8, 2019 Location: Atlanta, GA (hosted by NERC) Duration: 1 Day Chair: David Devereaux – IESO Vice-Chair: Chris Pilong – PJM

2019 Initiatives: We continue to focus on regular review, update, and communication of Guidance Documents and Reference Guides within our area of responsibility. We also continue to prepare for implementation of the IDC PFV, following the ongoing field trial. Throughout 2019, we will be monitoring RC developments in the Western Interconnection and will collaborate with other sub-groups to examine improvements in short and mid-term forecasting. Items for OC Approval:

None Key Issues for OC Information:

The ORS has endorsed the initial California ISO Reliability Plan. The Plan outlines their operation for the period beginning July 1, 2019. The Plan will be revised as their footprint expands.

The ORS endorsed minor changes to the MISO Reliability Plan. The minor changes were required to reflect a new Local Balancing Authority within the MISO footprint. Henderson Municipal Power and Light is currently completing the registration process to begin LBA operation.

The ORS was briefed by BC Hydro on their preparations to begin RC operation. BC Hydro will present their Reliability Plan to ORS in May. Shadow Operations are planned to begin in July. September 2 is the planned go-live date.

The ORS was briefed by SPP on their preparations to begin RC operation for the Mountain West area. Hiring of RC operators is underway. December 3 is the planned go-live date.

The Chairs of ORS and RS presented overviews of the activities of their respective Subcommittees at each other’s recent meetings. The groups will continue to look at ways to assist each other with their work plans.

As part of the 2019 ORS Work Plan, task teams have been formed to review:

Time Monitoring and GMD Reference Documents – The task team will be coordinated with the Resources Subcommittee and will include RS membership.

Dynamic Transfer Reference Document – The ORS will lead a joint task team with the RS to review the Reference Document and examine whether materials from the Pseudo Tie Coordination Reference Document and Dynamic Tag Exclusion Reference Documents can be incorporated. If so, the three documents will be replaced by a single Reference Document.

ORS continues to receive updates from the EIDSN Steering Committee on the IDC Tool enhancements. Specifically, the Parallel Flow Visualization (PFV) project is intended to improve the data quality used by the IDC during curtailment of transactions and may eventually result in changes to both NERC Reliability Standards and NAESB Business Practices. The 12-18 month field trial began on schedule in September 2017. Throughout the field trial, ORS has been receiving updates on tool performance from the IDCWG. The IDC Working Group has advised that there is a slight risk to the project schedule due to the volume of work required by the member companies. However, the group still feels that the PFV should be ready for OC approval in 2019.

The SMS briefed ORS on the January 11 system oscillation event. The group further discussed the event to discuss lessons learned from a coordination perspective. Several members had participated in a call on January 12, and noted its value. The call was coordinated by NERC SA staff and included RS members. ORS will examine how to capture this approach as a best practice for future events.

The Time and GMD Monitor roles will transition from Saskatchewan Power to South Eastern RC on February 1, 2020. ORS will work with both parties to ensure a smooth transition.

Current Initiatives/ Deliverables:

ORS has reviewed and discussed the 2019 OC work plan and continues to work items in the plan as prioritized by the OC

Recurring Deliverables of Group

Provide subcommittee report for the regularly scheduled Operating Committee meetings.

Endorse new or revised RC Reliability Plans.

Develop comments on the annual State of Reliability report.

Review the use of Proxy Flow Gates.

Review TLR 5 events as requested.

Review of EEA events.

Develop comments on Adequate Level of Reliability metrics.

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

NERC Program’s Oversight Responsibility for the Group

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

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

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

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

Guidelines and Reference Documents

Page 1 of 28 March 1, 2019

Midcontinent Independent System Operator

Regional Transmission Organization (RTO)

Reliability Plan

March 1, 2019


Document Change History

Issue Reason for Issue Date

Version 0 Reformatted and updated MISO RTO Reliability Plan to meet

the terms of NERC Operating Standards as approved by

NERC.

11/3/05

Version 1 Removed LGEE and DEVI from Reliability Coordination

Area. Added Southern Minnesota Municipal Power Agency to

MISO tariff.

9/20/06

Version 2 Reflected Ameren’s reconfiguration of their Balancing Areas

from three into two.

2/2/07

Version 3 Reflects the de-certification of the Western Plains East Kansas

(WPEK) Balancing Area

4/1/07

Version 4 Reflects the conception of the MISO Balancing Authority. To

be effective with the start of MISO Balancing Authority

operations.

11/14/07

Version 5 Reflects the addition of Duquesne Light Company (DLCO)

local Balancing Authority into the MISO Balancing Authority.

To be effective with the start of DLCO into MISO Balancing

Authority and MISO Market.

05/07/08

Version 6 Reflects moving Missouri Public Service -Aquila Networks

(MPS) Balancing Authority from MISO to SPP RC. To be

effective with the move of MPS to SPP RC.

11/19/08

Version 7 Reflects Duquesne Light Company’s (DLCO) decision to not

become a Local Balancing Authority in MISO Balancing

Authority Area.

Reflects moving LES, NPPD, and OPPD from MISO RC Area

to SPP RC Area. To be effective with the move of LES, NPPD,

and OPPD to SPP RC.

Reflects starting to provide Cleveland Public Power Reliability

Coordination services to be effective with the start of the

service.

01/31/09

Version 8 Reflects MidAmerican Energy Company (MEC) and

Muscatine Power and Water (MPW) changing from Balancing

Authorities (BAs) to Local Balancing Authorities (LBAs) and

being incorporated into Midwest ISO Balancing Authority

Area. Midwest ISO Reliability Coordination Area boundaries

are not changing with this version. This version becomes

effective with the incorporation of MEC and MPW LBAs into

Midwest ISO BA.

06/23/09

Version 9 Reflects the addition of Cedar Falls Utilities (CFU) and other

miscellaneous updates

9/23/09

Version 10 Reflects Dairyland Power Cooperative (DPC) changing from 1/8/10


Balancing Authority (BA) to Local Balancing Authority (LBA)

and being incorporated into Midwest ISO Balancing Authority



effective with the incorporation of DPC LBA into Midwest

ISO BA.

Version 11 Reflects Big Rivers Electric Corporation (BREC) Balancing

Area moving from TVA RC to Midwest ISO RC. Also reflects

BREC changing from Balancing Authority (BA) to Local

Balancing Authority (LBA) and being incorporated into

Midwest ISO BA Area. Note that depending on state

regulatory approval, BREC BA integration into Midwest ISO

BA may occur subsequent to Midwest ISO becoming BREC’s

RC. This version becomes effective with the BREC BA

moving into Midwest ISO RC Area.

5/10/10

Version 12 Reflects First Energy LBA exiting the Midwest ISO BA and

the Midwest ISO Reliability Footprint, scheduled for June 1,

2011 and Cleveland Public Power exiting its Reliability

Coordination Services Agreement with the Midwest ISO,

scheduled for June 1, 2011

2/9/11

Version 13 Reflects Missouri River Energy Services becoming a

Transmission Owning member of the Midwest ISO and Ohio

Valley Electric Corporation and Department of Energy taking

Reliability Coordination Services from Midwest ISO scheduled

for June 1, 2011.

5/4/11

Version 14 Reflects Lansing Board of Water and Light taking Reliability

Coordination Services from MISO. This version becomes

effective when LBWL begins RC Services with MISO

(currently scheduled for September 1, 2011).

8/11/2011

Version 15 Reflects Duke Energy Ohio and Kentucky LBA exiting the

MISO BA and the MISO Reliability Footprint, scheduled for

January 1, 2012. Duke Energy Indiana remains in the MISO

BA and MISO Reliability Footprint

11/15/2011

Version 16 Reflects Entergy taking Reliability Coordination Services from

MISO. This version becomes effective when Entergy begins

RC services with MISO (currently scheduled for November 19,

2012).

3/2/12

Version 17 Reflects Entergy (EES) Balancing Area changing from a


and being incorporated into MISO BA Area (currently

scheduled for December 19, 2013). Also included in this

revision are multiple Balancing Authorities that are expected to

join the MISO RC area on June 1, 2013 and subsequently the

MISO BA area on December 19.2013. The BAs included are

City of Conway (CWAY), Brazos Electric Corporation

(BRAZ), CLECO, Lafayette Utility System (LAFA), Louisiana

Energy and Power Authority (LEPA), Louisiana Generating

(LAGN), Plum Point Energy Associates (PLUM), City of

Osceola (OMLP), City of West Memphis (WMU), City of

1/1/13


North Little Rock (NLR), City of Benton (BUBA), Union

Power Partners (PUPP), City of Ruston (DERS), South

Mississippi Electric (SME), The listing of BAs above is based

on BAs defined on 1/1/13. The BAs are also evaluating the BA

boundaries and may determine to change their BA boundaries.

This version becomes effective with the BAs listed, pending

regulatory approvals, Regional Entity/NERC certifications)

moving into MISO RC Area and subsequently the MISO BA

Area.

Version 18 Reflects the Eagan Control Center move from St. Paul,

scheduled for December, 2013 and the Midwest ISO name

change to Midcontinent ISO, already completed.

11/20/2013

Version 19 Reflects a clean-up from December 19, 2013 South Region

Integration (removing dissolved BAs, removing footnotes,

etc.), adding AECC and City of Ames as a Transmission

Owners, MIUP as a new LBA, and adding City of Alexandria

and Consumers Energy as Reliability Services Customers.

5/8/2014

Version 20 Reflects the move of the Integrated System (WAPA, Basin

Electric, and Heartland Consumers Power District) and Corn

Belt Power Cooperative to the SPP Reliability Coordination

Footprint scheduled for June 1, 2015. Also reflects additional

Transmission Owners in MISO of Rochester Public Utilities,

City of Alexandria (LA), City of Marshall (MN), already

completed or scheduled in 2015, and the addition of Entergy

Mississippi as a Local Balancing Area in the MISO Balancing

Authority Area. Added Little Rock, AR as a MISO Control

Center scheduled for June, 2015.

3/20/2015

Version 21 Local Balancing Area Entergy Mississippi Abbreviation

change from EMI to EMBA, Pioneer Transmission becoming a

Transmission Owner, and AEP becoming a MISO TOP

5/8/2018

Version 22 Ohio Valley Electric Corp transferring from the MISO

Reliability Footprint to PJM on 12/1/2018 and updating the

South Mississippi Electric Power Association to Cooperative

Energy. Clean up of directives to operating instructions and

SOL/IROL violations to exceedances.

12/1/2018

Version 23 Henderson Municipal Power & Light entering MISO as an

LBA and Transmission Owner and AEP Indiana Michigan

Transmission Company, Inc. entering as a Transmission

Owner.

3/1/2019


Table of Contents

Introduction .............................................................................................................. 6

A. Responsibilities – Authorization ....................................................................... 7

B. Responsibilities – Delegation of Tasks ............................................................ 8

C. Common Tasks for Next-Day and Current-Day Operations ............................ 9

D. Next-Day Operations ........................................................................................ 12

E. Current-Day Operations ................................................................................... 14

F. Emergency Operations .................................................................................... 18

G. System Restoration ......................................................................................... 19

H. Coordination Agreements and Data Sharing ................................................. 20

I. Facility ................................................................................................................ 21

J. Staffing .............................................................................................................. 23

Appendix A ............................................................................................................. 25

Appendix B ............................................................................................................. 26

Appendix C ............................................................................................................. 28


Introduction

The North American Electric Reliability Corporation (NERC) requires every Region,

sub-region, or interregional coordinating group to establish a Reliability Coordinator

(RC) to provide the reliability assessment and emergency operations coordination for the

Balancing Authorities (BAs) and Transmission Operators (TOPs) within the Regions and

across the Regional boundaries.

The Midcontinent Independent System Operator (MISO) serves as the RC for its

members, under coordination agreements, and under RC agreements. The MISO RC has

certain defined responsibilities and directs the reliable operation of Bulk Power System

which is, in general, 100 kV facilities and higher. The MISO RC functions associated

with the reliability of the Bulk Power System include review and approval of planned

facility transmission line outages1 & generation outages2 based upon current and

projected system conditions, monitoring of real time loading information and calculating

post-contingent loadings on the transmission system, administering loading relief

procedures, re-dispatch of generation, and ordering curtailment of transactions and/or

load. The MISO RC functions associated with power supply reliability entails monitoring

BA performance and ordering the BAs to take actions, including load curtailment and

increasing/decreasing generation in situations where an imbalance between generation

and load places the system in jeopardy. The MISO reliability procedures and policies are

consistent with NERC Standards.3 MISO operates in multiple NERC Regions and

recognizes each Region’s policies and standards. Where there are conflicts in the

Regional policies and standards, MISO works with the Regions and members on

resolving those conflicts. MISO also provides RC Services for non-market members via

Module F.

This document is the Reliability Plan for the MISO RC and is posted at

https://www.nerc.com/comm/OC/Pages/ORS/Reliability-Plans.aspx. This version

supersedes the previous version.

1 For those Non-market members within MRO, MISO reviews all planned facility transmission line outages for these entities,

notifies the entities of possible conflicts or system conditions that would warrant reconsideration of these planned outages, and

works with the entities – along with MISO members - to resolve any issues. Further revisions of NERC Standards may render

this distinction obsolete.

2 MISO discusses and coordinates pending generation maintenance outages to the extent possible, as MISO has authority to deny

generation maintenance outages only in cases where such outages would place MISO in an emergency situation.

3 While the MISO Reliability Coordination Plan describes MISO’s general practices of providing RC services and in some

circumstances MISO RC’s endeavor to use best practices beyond what is required by the NERC Reliability Standards , Nothing

in this plan shall require MISO RC to go beyond what is required by the NERC Reliability Standards with regard to meeting

NERC compliance requirements.

https://www.nerc.com/comm/OC/Pages/ORS/Reliability-Plans.aspx

___________________________________________________________________________________________


A. Responsibilities – Authorization

1. Reliable Operations - MISO has certain defined responsibilities for the reliable operation of the Bulk

Power System within the its RC Area in accordance with NERC Standards, Regional policies and

standards, as well as the governing documents listed in Appendix C of this document. The MISO

RC Area is composed of the Transmission Owners’ Areas listed in Appendix A.

1.1 The MISO RC has a Wide Area view of its RC Area and neighboring areas that have an impact

on MISO’s Area. The MISO RC and MISO BA have the operating tools, processes and

procedures, including the authority, to prevent or mitigate emergency operating situations in both

next-day analysis and during real-time conditions per the NERC Standards and Regional

standards, as well as the governing documents listed in Appendix C of this document.

The MISO RC operating tools, which provide the Wide Area View, are listed in Section I.

1.2 The MISO RC has clear decision-making authority to act and to direct actions to be taken by its

members and non-MISO members within its Reliability Coordination Area to preserve the

integrity and reliability of the Bulk Power System.

1.3 The MISO RC and the MISO BA have not delegated any of its RC or BA responsibilities.

2. Independence - MISO does and will act first and foremost in the best interest of the reliability for its

RC Area and the Eastern Interconnection before that of any other entity. This expectation is clearly

identified in the governing documents listed in Appendix C and in the job descriptions of the MISO

personnel acting in the role of RC or BA.

3. MISO RC Operating Instructions Compliance - Per the governing documents in Appendix C, the

BAs, TOPs and other operating entities in the MISO RC Area shall carry out required emergency

actions as given in operating instructions by the MISO RC, including the shedding of firm load if

required, except in cases involving endangerment to the safety of employees or the public. In those

cases, members of the MISO RC Area must immediately inform the MISO RC of the inability to

perform the operating instruction.

___________________________________________________________________________________________


B. Responsibilities – Delegation of Tasks

1. The MISO RC and the MISO BA have not delegated any RC or BA tasks. Local Balancing

Authorities (LBAs) within the MISO Balancing Area are responsible for and will perform tasks per

the MISO BA/LBA Coordinated Functional Registration with NERC and the MISO Amended BA

Agreement.

___________________________________________________________________________________________


C. Common Tasks for Next-Day and Current-Day Operations

This section documents how the MISO conducts current-day and next-day reliability analysis for its

Reliability Coordination Area.

1. Determination of Interconnection Reliability Operating Limits (IROLs) – The MISO RC determines

IROLs based on local, regional and inter-regional studies including seasonal assessments and ad hoc

studies. As required, the voltage stability IROLs are calculated in the next day security analysis and

limits are conveyed to neighboring RCs and TOPs in the MISO RC Area via the next day security

analysis report. The IROL limits are also reviewed each weekday morning during reliability

conference calls.

During the operating day, real time voltage stability analyses are performed to provide updated

IROLs, based on the latest system conditions, to the MISO RC. Significant IROL changes are

communicated to impacted TOPs in the MISO RC Area and neighboring RCs by email and phone as

necessary. Standing IROL interfaces are highlighted in bold in MISO operator displays to

differentiate them from System Operating Limit (SOL) flowgates.

During real time operations, the MISO RC recognizes that a new IROL limit can be created during

multiple, normally non-critical outage conditions and the MISO RC determines additional IROLs

real-time. To determine these additional IROLs, the MISO RC utilizes a state estimator and real time

contingency analysis to analyze real-time and first contingency conditions. These contingency

analyses are normally repeated every one to two minutes. In the event a first contingency would

cause a post-contingency flow of 125% of the emergency rating, it is automatically assumed the

SOL is now an IROL unless there are studies or system knowledge that the SOL is not an IROL. An

example of an SOL greater than 125% that would not be considered an IROL is a radial system that

would not result in uncontrolled cascading or collapse should the monitored element(s) trip.

Contingency analysis results indicating an unsolved contingency which is confirmed to be valid is

also considered to be an IROL.

2. Operation to prevent the likelihood of a SOL or IROL exceedance in another area of the

Interconnection and operation when there is a difference in limits - The MISO RC, through

agreements with its RC neighbors, coordinates operations to prevent the likelihood of an SOL or

IROL exceedance in another area. These agreements include data exchange, Available Transfer

Capability coordination, and Outage Coordination and are listed in Section H.

TOPs in the MISO RC Area are required to follow operating instructions provided by the MISO RC

per NERC Standards and operate to NERC Standards to prevent the likelihood that a disturbance,

action, or non-action in its Reliability Coordination Area will result in an SOL or IROL exceedance

in another area of the Interconnection.

When there is a difference in derived limits, MISO RC utilizes the most conservative limit until the

difference is resolved.

3. Operation under known and studied conditions and re-posturing without delay and no longer than 30

minutes - The MISO RC ensures that entities within its RC Area always operate under known and

___________________________________________________________________________________________


studied conditions and that they return their systems to a secure operating state following

contingency events within approved timelines, regardless of the number of contingency events that

occur or the status of their monitoring, operating and analysis tools. The MISO RC also ensures its

BAs and TOPs re-posture the system to within all IROLs following contingencies within Tv or 30

minutes, whichever is shorter.

On a daily basis, the MISO RC conducts next-day security analysis utilizing planned outages,

forecasted loads, generation commitment, and expected net interchange. The analyses include

contingency analysis, voltage stability analysis on key interfaces and a review of reactive reserves

for defined areas when appropriate. These analyses model peak conditions for the day and are

conducted utilizing first contingency (N-1) analysis. Results and mitigation are documented in the

Next-Day Security Analysis Report and distributed to MISO Reliability staff. The Next-Day

Security Analysis Report is also posted on the MISO Extranet secure website for distribution from

this secure website for TOPs and BAs in the MISO Reliability Coordination Area and neighbors to

view and download. Mitigation plans are formed as needed for potential exceedances determined in

the next day security analysis. Mitigation is of the form of additional unit commitment or may be

documented in an operating guide to be utilized by the MISO RC and TOP.

MISO performs Current Day Security Analysis studies in the operating day for morning, peak or

near-peak and minimum load periods. The voltage stability analyses are also performed continuously

and on demand as system conditions warrant for each voltage stability flowgate. Current Day

analysis is documented in the MISO Current Day Security Analysis Report that is distributed to

MISO Reliability staff, and analysis data is posted to the MISO Extranet for the TOPs and BAs in

the MISO Reliability Coordination Area and neighbors.

The MISO Daily Reliability Coordination Report is also posted on the MISO Extranet secure web

site for TOPs and BAs in the MISO Reliability Coordination Area and neighbors to view and

download. The MISO Daily Reliability Coordination Report includes significant generation

outages, significant line outages, projected constraints, voltage security assessment results, reactive

reserves for defined areas when appropriate, TLR summary from the past 24 hours, and forecasted

weather conditions. The MISO Daily Reliability Coordination Report is reviewed each weekday

morning with TOPs, the MISO BA, Balancing Areas in the MISO Reliability Coordination Area,

and neighboring RCs where expected system conditions for the day are discussed, along with action

required to mitigate any abnormal conditions. Additional conference calls are conducted with the

same group when conditions warrant.

4. Communicating SOLs and IROLs to Transmission Service providers within RC Area – MISO

communicates IROLs within its wide-area view and provides updates to IROLs as described above

via reports, morning conference calls, and real-time via voice and messaging. Standing IROLs are

documented and communicated via operating guides. In general, SOLs are in the form of thermal

equipment limits and are provided by Transmission Owners to MISO. If transmission service is sold

on the IROL or SOL Flowgate, an adjustment is made to the AFC to account for the reservation.

5. MISO RC and BA process for issuing operating instructions - MISO has implemented a

communication protocol for the issuing/receiving of operating instructions. The MISO RC and/or

MISO BA issues operating instructions in a clear, concise and definitive manner. The MISO RC

and/or MISO BA ensures that the person receiving the operating instruction repeats the information

back correctly, and acknowledges the response as correct or repeats the original statement again to

___________________________________________________________________________________________


resolve any misunderstandings. MISO’s process for issuing operating instructions is documented in

the “Communications Protocol For Operating Instructions” procedure.

___________________________________________________________________________________________


D. Next-Day Operations

This section documents how the MISO conducts next-day reliability analysis for its Reliability

Coordination Area.

1. Reliability Analysis and System Studies - The MISO RC conducts next-day reliability analyses for

its Area to ensure that the Bulk Power System can be operated reliably in normal and post

contingency conditions.

On a daily basis, the MISO RC conducts next-day security analysis utilizing known outages,

forecasted loads, generation commitment and dispatch, and expected net interchange. All facilities

100 kV and above and some non-BES facilities in the MISO RC Area and first tier Balancing Areas

are monitored for all contingency cases and the base case. Base case flows on all monitored

facilities are compared against the normal rating. Post-contingent flows for all monitored facilities

are compared against their emergency rating for all contingencies. Voltage and transient stability

analysis is conducted on key critical interfaces to determine a flow limit. Reactive reserves for

specific areas are reviewed to ensure they are above necessary levels.

Mitigation plans are formed as needed for potential violations determined in the next day security

analysis. Mitigation is of the form of additional unit commitment, restriction on unit output, or may

be documented in an operating guide to be utilized by the MISO RC and TOPs.

1.1 Parallel Flows – The MISO RC monitors parallel flows to ensure that its Reliability Coordination

Area does not burden another Reliability Coordination Area. To ensure that the impact of

parallel flows is considered in the next day security analysis, all first tier BA Areas and key

second and third tier BA Areas are modeled in detail and updated in the analysis each day. This

includes updating their unit status, transmission outages, load forecast, interchange and

generation dispatch.

2. Information Sharing – BAs, Generation Operators and TOPs in the MISO Reliability Coordination

Area and neighboring RCs provide to the MISO RC all information required for system studies, such

as critical facility status, load, generation, and Operating Reserve projections via the SDX. The

entities in the MISO Reliability Coordination Area provide generation and transmission facility

statuses to the MISO outage scheduling application per MISO outage scheduling requirements.

MISO Reliability Coordination Area load forecast is provided in the SDX. MISO BA load is

determined by MISO load forecasting tools. Known interchange transactions are provided as NERC

E-Tags. MISO obtains the equivalent information for entities outside the MISO Reliability

Coordination Area from the SDX and NERC E-Tags.

3. Sharing of Study Results - When conditions warrant or upon request, the MISO RC shares the

results of its system studies with the entities within its Reliability Coordination Area or with other

RCs. Study results for the next day typically are available no later than 16:00 Eastern Standard Time,

unless circumstances warrant otherwise.

Next-Day Security Analysis Report is distributed to MISO Reliability staff. The Next-Day Security

Analysis Report is also posted on the MISO Extranet secure website for distribution to TOPs and

___________________________________________________________________________________________


BAs in the MISO Reliability Coordination Area and neighboring RCs to view and download. Any

reliability entity that is subject to the NERC Data Confidentiality Agreement may access the Next-

Day Security Analysis Report, with approved access, via the MISO Extranet secure web site.

The MISO RC has procedures indicating when it will initiate a conference call or other appropriate

communications to address the results of its reliability analyses. The MISO RC hosts a conference

call each business day that is normally utilized for this purpose.

___________________________________________________________________________________________


E. Current-Day Operations

This section documents how the MISO conducts current-day reliability analysis for its Reliability

Coordination Area.

1. The process MISO RC uses to monitor all Bulk Power System facilities, including sub-transmission

information as needed, within the MISO Reliability Coordination Area and adjacent areas as

necessary to ensure that, at any time, regardless of prior planned or unplanned events, the MISO RC

is able to determine any potential SOL and IROL exceedances within its Reliability Coordination

Area is as follows:

MISO RC utilizes a state estimator and real-time contingency analysis as its primary tool to monitor

facilities. The state estimator model includes all facilities 100 kV and above in the MISO Reliability

Coordination Area and extensive representation of 69 kV facilities. The model also has extensive

representation of neighboring facilities in order to provide an effective wide-area view. This model

is updated quarterly and may be updated on demand when deemed necessary.

Real Time Contingency Analysis (RTCA) is performed on over 10,000 contingencies utilizing the

state estimator model normally at least every five minutes. Contingencies include all MISO

Reliability Coordination Area equipment 100 kV and above, some non-BES equipment, and

neighboring contingencies that would impact MISO Reliability Coordination Area facilities.

MISO utilizes a Real-Time Line Outage Distribution Factor (RTLODF) Tool to monitor selected

PTDF and OTDF flowgates to provide a backup to RTCA monitoring. Post-contingent loading on

OTDF flowgates is calculated using SCADA data and LODFs automatically updated from a

topology processor that does not rely on the state estimator solution.

SCADA alarming is utilized to alert the MISO RC of any actual low or high voltages or facilities

loaded beyond their normal or emergency limits.

In addition to the above applications, MISO utilizes a dynamically updated transmission overview

display to maintain a wide area view. Transmission facilities 230 kV and above are depicted on the

overview with flows (MW and MVAR). This display provides indication of facilities out of service,

high and low voltage warning and alarming, and facilities loaded to 90% and 100% of ratings. For

more detailed monitoring, dynamically updated Balancing Area wide displays are used to view

facilities 100 kV and above, including flows (MW and MVAR), voltages, generator outputs, and

facilities out of service. Finally, bus level one-line diagrams are utilized for station level information.

1.1. The MISO RC notifies neighboring RCs of operational concerns (e.g. declining voltages,

excessive reactive flows, or an IROL exceedance) that it identifies within the neighboring

Reliability Coordination Area via direct phone calls, conference calls, NERC hotline calls,

and/or RCIS messages. The MISO RC has documented seams agreements with neighboring

RCs that are listed in Section H. MISO RC directs action to provide emergency assistance to

all Reliability Coordination neighbors, during declared emergencies, which is required to

mitigate the operational concern to the extent that the same entities are taking in kind steps

and the assistance would be effective.

___________________________________________________________________________________________


2. The MISO RC maintains awareness of the status of all current critical facilities whose failure,

degradation or disconnection could result in an SOL or IROL exceedance within its Reliability

Coordination Area via State Estimator, RTCA, SCADA alarming, and transmission displays. The

MISO RC is aware of the status of any facilities that may be required to assist Reliability

Coordination Area restoration objectives via these same displays and tools.

3. The MISO RC is continuously aware of conditions within its Reliability Coordination Area includes

this information in its reliability assessments via automatic updates to the state estimator, Flowgate

Monitoring Tool, and transmission displays. The MISO RC monitors its MISO Reliability

Coordination Area parameters, including the following:

3.1. Current status of Bulk Power System elements (transmission or generation including critical

auxiliaries such as Automatic Voltage Regulators and Special Protection Systems and system

loading are monitored by state estimator, RTCA, SCADA Alarming, Flowgate Monitoring

Tool, and transmission displays. Balancing Areas are required to report to MISO RC when

Automatic Voltage Regulators are not in-service. TOPs are required to report to the MISO

RC when Special Protection Systems change status.

3.2. Current pre-CONTINGENCY element conditions (voltage, thermal, or stability) are monitored

by state estimator, SCADA Alarming, Flowgate Monitoring Tool, and transmission displays.

3.3. Current post-CONTINGENCY element conditions (voltage, thermal, or stability) are monitored

by RTCA, Flowgate Monitoring Tool, and transmission displays.

3.4. System real reserves are monitored versus required per Balancing Area in the Market

Monitoring Tool. Reactive reserves versus required are monitored via monitoring adequacy

of calculated post-contingent steady state voltages versus voltage limits, voltage stability

interfaces against limits, and reactive reserves versus required for defined zones.

3.5. Capacity and energy adequacy conditions via monitoring reserve requirements and regional

reporting.

3.6. Current ACE for all Balancing Areas is displayed in a trend graph to MISO RC. When ACE

exceeds L10, graph changes colors and alerts operator of magnitude of ACE and duration

ACE has exceeded L10 .

3.7. Current local procedures, such as operating guides, monitored via discussions with local TOP

and statuses of their use are logged in the MISO RC log. TLR procedures in effect are

monitored via the NERC Interchange Distribution Calculator.

3.8. Planned generation dispatches for MISO market area are provided to the MISO RC in the

form of the unit commitment plan. For the non-market area, generation outages are reported

to MISO via the MISO Outage Scheduler application.

3.9. Planned transmission or generation outages are reported to MISO via the MISO Outage

Scheduler application.

___________________________________________________________________________________________


3.10. Contingency Events are monitored by state estimator, RTCA, SCADA Alarming, Flowgate

Monitoring Tool, and transmission displays. TOPs and BAs are required to report

Contingency Events to MISO RC.

4. The MISO RC monitors Bulk Power System parameters that may have significant impacts upon its

Reliability Coordination Area and neighboring Reliability Coordination areas with respect to:

4.1. The MISO RC maintains awareness of all Interchange Transactions that wheel-through,

source, or sink in its Reliability Coordination via NERC E-tags and NERC IDC displays.

Interchange Transaction information is made available to all RCs via NERC E-tags.

4.2. The MISO RC, in concert with the Balancing and Interchange Authorities within its

Reliability Coordination Area, evaluates and assesses any additional Interchange

Transactions that would exceed IROL or SOLs by using the NERC IDC as a look-ahead tool.

As flows approach their IROL or SOLs, the MISO RC evaluates the incremental loading

next-hour transactions would have on the SOLs or IROLs and determines if action needs to

be taken to prevent an SOL or IROL exceedance. The MISO RC has the authority to direct

all actions necessary and may utilize all resources to address a potential or actual IROL

exceedance up to and including load shedding.

4.3. The MISO RC and MISO BA monitors Balancing Area Operating Reserves versus required

to ensure the required amount of Operating Reserves are provided and available as required

to meet NERC Control Performance Standards via the Market Monitoring Tool. The MISO

RC and the MISO BA are alerted if reserves fall below required. If necessary, the MISO RC

will direct the Balancing Area to replenish reserves including obtaining assistance from

neighbors as needed.

4.4. The MISO RC identifies the cause of potential or actual SOL or IROL exceedances via

analysis of state estimator results, RTCA results, SCADA Alarming of outages, Flowgate

Monitoring Tool results, transmission displays of changes, and Interchange Transaction

impacts. The MISO RC will initiate control actions including transmission switching,

generation redispatch, and/or emergency procedures to relieve the potential or actual IROL

exceedance without delay, and no longer than 30 minutes. The MISO RC is authorized to

direct utilization of all resources, including load shedding, to address a potential or actual

IROL exceedance. The MISO RC will not rely solely on NERC TLR to mitigate an IROL

exceedance.

4.5. The MISO RC communicates start and end times for time error corrections to all Balancing

Areas within its Reliability Coordination Area via its messaging system. The MISO RC

communicates Geo-Magnetic Disturbance forecast information to BAs, TOPs, and

Generation Operators via its messaging system. MISO RC will assist in development of any

required response plan and will establish an Emergency Operating Guide as needed or move

to conservative operating mode to mitigate impacts as needed.

___________________________________________________________________________________________


4.6. The MISO RC (Carmel, Eagan, and Little Rock locations) participates in NERC Hotline

discussions, assist in the assessment of reliability of the Regions and the overall

interconnected system, and coordinate actions in anticipated or actual emergency situations.

The MISO RC will disseminate this information via text messaging, individual phone calls,

or blast calls within its area as appropriate.

4.7. The MISO RC monitors system frequency via trend graph. The graph visually alerts the

MISO RC when frequency falls below 59.95 Hz or is greater than 60.05 Hz. MISO BA

monitors its ACE, while the MISO RC monitors each Balancing Area’s ACE via trend graph

within the Reliability Coordination Area. Both the MISO BA and the MISO RC receive a

visual indication when ACE exceeds L10 and/or BAAL. When necessary, MISO RC directs

Balancing Areas with ACEs larger than L10 to return within L10, and directs Balancing Areas

to return to within BAAL. The MISO RC will direct BAs to utilize all resources, including

firm load shedding, as necessary to relieve an emergency condition.

4.8. The MISO RC coordinates with other RCs and its BAs, Generation Operators, and TOPs, as

needed, on the development and implementation of action plans and operating guides to

mitigate potential or actual SOL or IROL exceedances, or CPS1, BAAL, or Reportable

Balancing Contingency Event criteria.. The MISO RC coordinates pending generation and

transmission maintenance outages with other RCs and its BAs, Generation Operators, and

TOPs, as needed and within code of conduct requirements, real time via telephone and next-

day, per the MISO outage scheduling process.

4.9. The MISO RC will assist its BA Areas in arranging for assistance from neighboring RCs or

BA Areas via the Energy Emergency Alert (EEA) notification process and will conference

parties together as appropriate.

4.10. The MISO RC monitors Balancing Areas’ ACEs to identify the sources of large ACEs that

may be contributing to frequency, time error, or inadvertent interchange and directs

corrective actions with the appropriate BAs per 4.7 above.

4.11. The TOPs within MISO Reliability Area inform MISO of all changes in status of Special

Protection Systems (SPS) including any degradation or potential failure to operate as

expected by the TOP. The MISO RC factors these SPS changes into its reliability analyses.

5. The MISO RC issues alerts, as appropriate, to all its Balancing Areas and TOPs via dedicated text

messaging, individual phone calls, or blast calls when it foresees a transmission problem (such as an

SOL or IROL exceedance, loss of reactive reserves, etc.) within its Reliability Area that requires

notification. The MISO RC issues alerts, as appropriate, to all RCs via the Reliability Coordinator

Information System when it foresees a transmission problem (such as an SOL or IROL exceedance,

loss of reactive reserves, etc.) within its Reliability Area that requires notification.

6. The MISO RC confirms reliability assessment results via analyzing results of state estimator/RTCA,

and discussions with local TOPs and neighboring RCs. The MISO RC identifies options to mitigate

potential or actual SOL or IROL exceedances via examining existing operating guides, system

knowledge, and power flow analysis to identify and implement only those actions as necessary as to

always act in the best interests of the interconnection.

___________________________________________________________________________________________


F. Emergency Operations

1. The MISO RC utilizes the MISO Emergency Operating Procedures, posted on the

www.misoenergy.org site, to return the transmission system to within the IROL as soon as possible,

but no longer than 30 minutes. This procedure includes the actions (e.g. reconfiguration, re-dispatch

or load shedding) the MISO RC will direct until relief is achieved.

2. The MISO RC utilizes the MISO Emergency Operating Procedures when it deems that an IROL

exceedance are imminent. The MISO Emergency Operating Procedures documents the processes

and procedures the MISO RC follows when directing its BAs and TOPs to re-dispatch generation,

reconfigure transmission, manage Interchange Transactions, or reduce system demand to mitigate

the IROL exceedance, to return the system to a reliable state. The MISO RC coordinates its alert

and emergency procedures with other RCs via seam coordination agreements listed in Section H.

3. The MISO RC takes or directs action in the event the loading of transmission facilities progresses to

or is projected to progress to an SOL or IROL exceedance.

3.1 The MISO RC directs reconfiguration and/or re-dispatches within its market area as needed to

prevent or relieve SOL or IROL exceedances. In the non-market area of MISO Reliability

Coordination Area, the MISO RC will direct reconfiguration and re-dispatch to resolve IROL

exceedances. The MISO RC will not rely on or wait for NERC TLR to relieve IROL

exceedances. The MISO RC may implement NERC TLR if doing so will provide additional

relief.

3.2 The MISO RC utilizes market-to-market re-dispatch for its market area for reciprocally

coordinated flowgates per the Congestion Management Process posted on the

www.misoenergy.org site and filed with FERC.

3.3 The MISO RC acknowledges provisions of the NERC TLR and communicates curtailment

information as appropriate to impacted Balancing Authorities.

3.4 The MISO RC will initiate re-configuration, re-dispatch for market areas, and NERC TLR

reductions to relieve overloaded facilities as necessary. The MISO RC will not rely on NERC

TLR as an emergency action.

4. The MISO RC utilizes the MISO Emergency Operating Procedures to mitigate an energy emergency

within its Reliability Coordination Area. The MISO RC will provide assistance to other RCs per its

seams agreements listed in Section H.

5. The MISO RC utilizes the MISO Emergency Operating Procedures when it is experiencing a

potential or actual Energy Emergency within any BA, Reserve-Sharing Group, or Load-Serving

Entity within its Reliability Coordination Area. The MISO Emergency Operating Procedures

document the processes and procedures the MISO RC uses to mitigate the emergency condition,

including a request for emergency assistance if required.

___________________________________________________________________________________________


G. System Restoration

1. Knowledge of members’ Restoration Plans - The MISO RC is aware of each member’s Restoration

Plan and has a written copy of each plan. The MISO has the plans and procedures of every member,

which are listed in Appendix A.

During system restoration, MISO RC monitors restoration progress and acts to coordinate any

needed assistance.

2. MISO Restoration Plan - The MISO Restoration Plan includes all BAs and TOPs in its Reliability

Coordination Areas. MISO RC takes action to restore normal operations once an operating

emergency has been mitigated in accordance with its Restoration Plan. This Restoration Plan is

drilled at least annually.

3. Dissemination of Information - The MISO RC serves as the primary contact for disseminating

information regarding restoration to neighboring RCs and members not immediately involved in

restoration.

The MISO RC approves, communicates and coordinates the re-synchronizing of major system

islands or synchronizing points so as not to cause a burden on member or adjacent Reliability

Coordination Areas.

___________________________________________________________________________________________


H. Adjacent RC Agreements and Data Sharing

1. Coordination Agreements:

MISO and PJM have a Joint Operation Agreement

MISO and TVA have a RC Coordination and Notification Plan

MISO and IESO have a Coordination Agreement.

MISO and SPP have a Joint Operating Agreement.

MISO and Southeastern RC have a RC Coordination and Notification Plan.

MISO and SaskPower have a RC to RC Agreement.

2. Data Sharing - The MISO RC determines the data requirements to support its reliability coordination

tasks and requests such data from members or adjacent RCs. The MISO RC provides for data

exchange with members and adjacent RCs, TOPs and BAs via a secure network. MISO Reliability

Coordination Area members provide data to MISO via ICCP. MISO RC provides data to entities

outside MISO via direct links and ISN.

___________________________________________________________________________________________


I. Facility

MISO performs the RC function at the MISO Headquarters in Carmel, Indiana along with the MISO

offices in Eagan, Minnesota, and Little Rock, Arkansas. The Carmel, Eagan, and Little Rock offices

have the necessary voice and data communication links to appropriate entities within their Reliability

Coordination Area for the MISO RC to perform their responsibilities. These communication facilities

are staffed and available to act in addressing a real-time emergency condition.

1. Adequate Communication Links - The MISO RC maintains satellite phones, Voice Over IP phones

which run across the dedicated MISO WAN, cell phones, and redundant, diversely routed

telecommunications circuits. Additionally, there are also video links between MISO Carmel Control

Room and the MISO Eagan and Little Rock Control Rooms.

2. Multi-directional Capabilities – The MISO RC has multi-directional communications capabilities

with its members, and with neighboring RCs, for both voice and data exchange to meet reliability

needs of the Interconnection.

3. Real-time Monitoring - The MISO RC has detailed real-time monitoring capability of its Reliability

Coordination Area and all first tier companies surrounding the MISO Reliability Coordination Area

to ensure that potential or actual System Operating Limit or Interconnection Reliability Operating

Limit exceedances are identified.

3.1 The MISO RC monitors Bulk Power System elements (generators, transmission lines, buses,

transformers, breakers, etc.) that could result in SOL or IROL exceedances within its Reliability

Coordination Area. The MISO RC monitors both real and reactive power system flows, and

operating reserves, and the status of the Bulk Power System elements that are, or could be,

critical to SOLs and IROLs and system restoration requirements within its Reliability

Coordination Area.

4. Study and Analysis Tools

4.1 The MISO RC has adequate analysis tools, including state estimation, pre-and post-contingency

analysis capabilities (thermal, stability, and voltage), and wide-area overview displays. The

MISO RC has detailed monitoring capability of the MISO Reliability Area and sufficient

monitoring capability of the surrounding Reliability Areas to ensure potential reliability issues

are identified. The MISO RC continuously monitors key transmission facilities in its area in

conjunction with the Members monitoring of local facilities and issues.

The MISO RC ensures that SOL and IROL monitoring and derivations continue if the main

monitoring system is unavailable. The MISO RC has backup facilities that shall be exercised if

the main monitoring system is unavailable.

___________________________________________________________________________________________


The systems utilized by the MISO RC are:

State Estimator and Contingency Analysis

Market Monitoring Tool

Status and Analog Alarming

Overview Displays of MISO Transmission System via Wallboard

One line diagrams for entire MISO Transmission System

Transmission Delta Flow Tool

Flowgate Monitoring Tool

Generation Monitoring Tool

The MISO RC utilizes these tools, which provide information that is easily understood and

interpreted by the MISO RC operating personnel. The alarm management is designed to classify

alarms in priority for heightened awareness of critical alarms.

4.2 The MISO RC controls its RC analysis tools, including approvals for planned maintenance. The

MISO RC has procedures in place to mitigate the effects of analysis tool outages.

___________________________________________________________________________________________


J. Staffing

1. Staff Adequately Trained and NERC Certified - MISO maintains trained RCs, BAOs, and a Shift

Manager on duty at all times, as well shift Reliability Engineers. The MISO RC and MISO BA staff

all operating positions that meet following criteria with personnel that are NERC certified for the

applicable functions:

Positions that have the primary responsibility, either directly or through communications with

others, for the real-time operation of the interconnected Bulk Power System.

Positions directly responsible for complying with NERC Standards.

The MISO RC and MISO BA operating personnel each complete a minimum of 40 hours per year of

training and drills using realistic simulations of system emergencies, in addition to other training

required to maintain qualified operation personnel.

2. Comprehensive Understanding - The MISO RC operating personnel have an extensive

understanding of the BAs and TOPs within the MISO Reliability Coordination Area, including the

operating staff, operating practices and procedures, restoration priorities and objectives, outage

plans, equipment capabilities, and operational restrictions.

The MISO RC operating personnel place particular attention on SOLs and IROLs and inter-tie

facility limits. The MISO ensures protocols are in place to allow MISO RC operating personnel to

have the best available information at all times.

MISO’s System Operator Training process describes the process by which System Operations

personnel are trained to perform their duties, both at entry level and in continuous training status.

MISO also uses the Operator Training Manual to establish training and documentation requirements

for System Operators in the form of position specific curricula, NERC certification Guidelines, On-

the-Job qualification Guides, and Technical Qualification Training Checklists. The Technical

Qualification Training Checklists contain competencies for the RC System Operator position and

other operation positions. An analysis of each operator position was conducted by Subject Matter

Experts (SME), Management, and training representatives to develop the checklists. These checklists

provide a way to identify, track status, and document completion of required initial training for any

new System Operator.

MISO uses several means to provide initial and continuous training opportunities for System

Operators. MISO Operations Technical Training provides the majority of the technical training.

MISO Corporate Training provides much of the corporate and non-technical courses such as

Standards of Conduct, Fitness for Duty, Ethics and Employee Conducts and Disciplinary Guidelines.

Information Technology (IT) Education conducts training on computer-based applications such as

Word, Excel, Access Database, etc. Continuing training is designed to keep all operating personnel

knowledgeable of current policies, equipment and management expectations. Drills on emergency

procedures and simulated exercises are included in the on-going training activities. Training records

are maintained.

___________________________________________________________________________________________


3. Standards of Conduct - MISO RC and MISO BA are independent of the merchant function. RC and

BA Operators do not pass information or data to any wholesale merchant function or retail merchant

function that is not made available as soon as practicable to all such wholesale merchant functions.

MISO RC and MISO BA staff have completed training on MISO’s Standards of Conduct. Refresher

training on MISO’s Standards of Conduct is conducted every year. Training records are maintained.

___________________________________________________________________________________________


Appendix A

List of Transmission Owners within the MISO Reliability Coordination Area & the documents associated with each:

MISO Members MISO Authority Documents

MISO TO

Agreement

MISO Tariff Coordination

Agreement

RC Services

Agreement

Appendix I

AEP Indiana Michigan Transmission

Company, Inc. X X

AmerenCILCO X X

AmerenIP X X

AmerenUE and AmerenCIPS X X

American Transmission Company, LLC X X

Arkansas Electric Cooperative Corporation X X

Big Rivers Electric Corporation X X

CLECO X X

Central Minnesota Municipal Power Agency X X

City of Alexandria (LA) X X

City of Ames X X

City of Marshall (MN) X X

Dairyland Power Cooperative X X

Duke Energy Indiana, Inc. X X

East Texas Electric Cooperative, Inc X X

Entergy Arkansas, Inc. X X

Entergy Gulf States Louisiana, L.L.C. X X

Entergy Louisiana, LLC X X

Entergy Mississippi Inc. X X

Entergy New Orleans, Inc X X

Entergy Texas, Inc. X X

Cedar Falls Utilities X X

City of Columbia, MO X X

City Water, Light & Power (Springfield, IL) X X

Great River Energy X X

Henderson Municipal Power & Light X X

Hoosier Energy Rural Electric Cooperative X X

Indiana Municipal Power Agency X X

Indianapolis Power and Light X X

Lafayette Utility System X X

Louisiana Energy and Power Authority X X

Louisiana Generating X X

Michigan Electric Transmission Co, LLC X X

Michigan Public Power Agency X X

Michigan South Central Power Agency X X

MidAmerican Energy Company X X

Minnesota Power, Inc and subsidiary X X

Minnesota Municipal Power Agency X X

Missouri River Energy Services X X

Muscatine Power and Water X X

Montana-Dakota Utilities Co. X X

Northern Indiana Public Service Company X X

Northwestern Wisconsin Electric Company X X

Otter Tail Power Company X X

___________________________________________________________________________________________


Pioneer Transmission X X

Prairie Power X X

Rochester Public Utilities X X

Cooperative Energy X X

Southern Illinois Power Cooperative X X

Southern Minnesota Municipal Power Agency X X

Vectren for Southern Indiana Gas & Electric X X

Wabash Valley Power Association, Inc. X X

Wolverine Power Supply Cooperative, Inc. X X

Xcel Energy, Inc. X X

Manitoba Hydro X

International Transmission Company X

Non-MISO Members

Consumers Energy X

Lansing Board of Water and Light X

Minnkota Power Cooperative X

NorthWestern Energy X

Appendix B

Balancing Areas within the MISO Reliability Coordination Area

Balancing Area Name Balancing

Area

Local

BA

within

MISO

BA

Under

MISO

Tariff

Reliability

Coordination

Office

Carmel,

IN

Eagan,

MN

Little

Rock,

AR

0 Midcontinent ISO MISO - Yes X X X

1 Alliant Energy - CA - ALTE ALTE Yes Yes X

2 Alliant Energy - CA - ALTW ALTW Yes Yes X

3 Ameren Illinois AMIL Yes Yes X

4 Ameren Missouri AMMO Yes Yes X

5 Big Rivers Electric Corporation BREC Yes Yes X

6 Duke Energy CIN Yes Yes X

7 City Water Light & Power CWLP Yes Yes X

8 Columbia Water & Light CWLD Yes Yes X

9 Consumers Energy Company CONS Yes Yes X

10 Dairyland Power Cooperative DPC Yes Yes X

11 Detroit Edison Company DECO Yes Yes X

12 Entergy Arkansas EAI Yes Yes X

13 Entergy Electric System EES Yes Yes X

14 Entergy Mississippi EMBA Yes Yes X

15 Great River Energy GRE Yes Yes X

16 Henderson Municipal Power & Light HMPL Yes Yes X

17 Hoosier Energy HE Yes Yes X

18 Indianapolis Power & Light Company IPL Yes Yes X

19 MidAmerican Energy Company MEC Yes Yes X

20 Madison Gas and Electric Company MGE Yes Yes X

21 Michigan Electric Coordinated System MECS Yes Yes X

22 Michigan Upper Peninsula MIUP Yes Yes X

23 MHEB, Transmission Services MHEB No No X

___________________________________________________________________________________________


24 Minnesota Power, Inc. MP Yes Yes X

25 Montana-Dakota Utilities Co. MDU Yes Yes X

26 Muscatine Power and Water MPW Yes Yes X

27 Northern Indiana Public Service Company NIPS Yes Yes X

28 Northern States Power Company NSP Yes Yes X

29 Otter Tail Power Company OTP Yes Yes X

30 Southern Indiana Gas & Electric Co. SIGE Yes Yes X

31 Southern Illinois Power Cooperative SIPC Yes Yes X

32 Southern Minnesota Municipal Power Agency SMP Yes Yes X

33 Upper Peninsula Power Co. UPPC Yes Yes X

34 Wisconsin Energy Corporation WEC Yes Yes X

35 Wisconsin Public Service Corporation WPS Yes Yes X

36 CLECO CLECO Yes Yes X

37 Lafayette Utility System LAFA Yes Yes X

38 Louisiana Energy and Power Authority LEPA Yes Yes X

39 Louisiana Generating LAGN Yes Yes X

40 Cooperative Energy SME Yes Yes X

___________________________________________________________________________________________


Appendix C

Responsibilities and Authorities

The following lists the responsibilities/authorities of the MISO and the documents where those

responsibilities/authorities are defined.

MISO Responsibilities / Authorities

Document Responsibilities / Authorities MISO Transmission Owner Agreement Security and Reliability of the Transmission

System

Provide outage coordination

Take emergency action – including shedding load

MISO Tariff Curtailment of transmission service

Coordination Agreement Security and Reliability of the Transmission

System


Interconnection Agreements Agreement between Transmission Owners and

Generation Owners

Appendix “I” Security and Reliability of the Transmission

System

Outage coordination for independent transmission

Companies (ITC, METC)

RC Agreement Provide Reliability Coordination Services

Agreement Between Midcontinent ISO

and Midcontinent ISO BAs to Implement

TEMT

Agreement between Midcontinent ISO and BAs

that are signatories to the agreement. The

agreement does not apply to non-MISO members.

The agreement delineates the responsibilities

between Midcontinent ISO and the BAs as is

necessary to allow the TEMT, market tariff, to be

implemented.

MISO BA – Local BA Agreements The agreement documents the coordination of the

actions associated with the defined BA

responsibilities

Page 1 of 28 December March 1, 20198

Midcontinent Independent System Operator

Regional Transmission Organization (RTO)

Reliability Plan

December 1, 2018March 1, 2019


Document Change History

Issue Reason for Issue Date

Version 0 Reformatted and updated MISO RTO Reliability Plan to meet

the terms of NERC Operating Standards as approved by

NERC.

11/3/05

Version 1 Removed LGEE and DEVI from Reliability Coordination

Area. Added Southern Minnesota Municipal Power Agency to

MISO tariff.

9/20/06

Version 2 Reflected Ameren’s reconfiguration of their Balancing Areas

from three into two.

2/2/07

Version 3 Reflects the de-certification of the Western Plains East Kansas

(WPEK) Balancing Area

4/1/07

Version 4 Reflects the conception of the MISO Balancing Authority. To

be effective with the start of MISO Balancing Authority

operations.

11/14/07

Version 5 Reflects the addition of Duquesne Light Company (DLCO)

local Balancing Authority into the MISO Balancing Authority.

To be effective with the start of DLCO into MISO Balancing

Authority and MISO Market.

05/07/08

Version 6 Reflects moving Missouri Public Service -Aquila Networks

(MPS) Balancing Authority from MISO to SPP RC. To be

effective with the move of MPS to SPP RC.

11/19/08

Version 7 Reflects Duquesne Light Company’s (DLCO) decision to not

become a Local Balancing Authority in MISO Balancing

Authority Area.

Reflects moving LES, NPPD, and OPPD from MISO RC Area

to SPP RC Area. To be effective with the move of LES, NPPD,

and OPPD to SPP RC.

Reflects starting to provide Cleveland Public Power Reliability

Coordination services to be effective with the start of the

service.

01/31/09

Version 8 Reflects MidAmerican Energy Company (MEC) and

Muscatine Power and Water (MPW) changing from Balancing

Authorities (BAs) to Local Balancing Authorities (LBAs) and

being incorporated into Midwest ISO Balancing Authority



effective with the incorporation of MEC and MPW LBAs into

Midwest ISO BA.

06/23/09

Version 9 Reflects the addition of Cedar Falls Utilities (CFU) and other

miscellaneous updates

9/23/09

Version 10 Reflects Dairyland Power Cooperative (DPC) changing from 1/8/10



and being incorporated into Midwest ISO Balancing Authority



effective with the incorporation of DPC LBA into Midwest

ISO BA.

Version 11 Reflects Big Rivers Electric Corporation (BREC) Balancing

Area moving from TVA RC to Midwest ISO RC. Also reflects

BREC changing from Balancing Authority (BA) to Local

Balancing Authority (LBA) and being incorporated into

Midwest ISO BA Area. Note that depending on state

regulatory approval, BREC BA integration into Midwest ISO

BA may occur subsequent to Midwest ISO becoming BREC’s

RC. This version becomes effective with the BREC BA

moving into Midwest ISO RC Area.

5/10/10

Version 12 Reflects First Energy LBA exiting the Midwest ISO BA and

the Midwest ISO Reliability Footprint, scheduled for June 1,

2011 and Cleveland Public Power exiting its Reliability

Coordination Services Agreement with the Midwest ISO,

scheduled for June 1, 2011

2/9/11

Version 13 Reflects Missouri River Energy Services becoming a

Transmission Owning member of the Midwest ISO and Ohio

Valley Electric Corporation and Department of Energy taking

Reliability Coordination Services from Midwest ISO scheduled

for June 1, 2011.

5/4/11

Version 14 Reflects Lansing Board of Water and Light taking Reliability

Coordination Services from MISO. This version becomes

effective when LBWL begins RC Services with MISO

(currently scheduled for September 1, 2011).

8/11/2011

Version 15 Reflects Duke Energy Ohio and Kentucky LBA exiting the

MISO BA and the MISO Reliability Footprint, scheduled for

January 1, 2012. Duke Energy Indiana remains in the MISO

BA and MISO Reliability Footprint

11/15/2011

Version 16 Reflects Entergy taking Reliability Coordination Services from

MISO. This version becomes effective when Entergy begins

RC services with MISO (currently scheduled for November 19,

2012).

3/2/12

Version 17 Reflects Entergy (EES) Balancing Area changing from a


and being incorporated into MISO BA Area (currently

scheduled for December 19, 2013). Also included in this

revision are multiple Balancing Authorities that are expected to

join the MISO RC area on June 1, 2013 and subsequently the

MISO BA area on December 19.2013. The BAs included are

City of Conway (CWAY), Brazos Electric Corporation

(BRAZ), CLECO, Lafayette Utility System (LAFA), Louisiana

Energy and Power Authority (LEPA), Louisiana Generating

(LAGN), Plum Point Energy Associates (PLUM), City of

Osceola (OMLP), City of West Memphis (WMU), City of

1/1/13


North Little Rock (NLR), City of Benton (BUBA), Union

Power Partners (PUPP), City of Ruston (DERS), South

Mississippi Electric (SME), The listing of BAs above is based

on BAs defined on 1/1/13. The BAs are also evaluating the BA

boundaries and may determine to change their BA boundaries.

This version becomes effective with the BAs listed, pending

regulatory approvals, Regional Entity/NERC certifications)

moving into MISO RC Area and subsequently the MISO BA

Area.

Version 18 Reflects the Eagan Control Center move from St. Paul,

scheduled for December, 2013 and the Midwest ISO name

change to Midcontinent ISO, already completed.

11/20/2013

Version 19 Reflects a clean-up from December 19, 2013 South Region

Integration (removing dissolved BAs, removing footnotes,

etc.), adding AECC and City of Ames as a Transmission

Owners, MIUP as a new LBA, and adding City of Alexandria

and Consumers Energy as Reliability Services Customers.

5/8/2014

Version 20 Reflects the move of the Integrated System (WAPA, Basin

Electric, and Heartland Consumers Power District) and Corn

Belt Power Cooperative to the SPP Reliability Coordination

Footprint scheduled for June 1, 2015. Also reflects additional

Transmission Owners in MISO of Rochester Public Utilities,

City of Alexandria (LA), City of Marshall (MN), already

completed or scheduled in 2015, and the addition of Entergy

Mississippi as a Local Balancing Area in the MISO Balancing

Authority Area. Added Little Rock, AR as a MISO Control

Center scheduled for June, 2015.

3/20/2015

Version 21 Local Balancing Area Entergy Mississippi Abbreviation

change from EMI to EMBA, Pioneer Transmission becoming a

Transmission Owner, and AEP becoming a MISO TOP

5/8/2018

Version 22 Ohio Valley Electric Corp transferring from the MISO

Reliability Footprint to PJM on 12/1/2018 and updating the

South Mississippi Electric Power Association to Cooperative

Energy. Clean up of directives to operating instructions and

SOL/IROL violations to exceedances.

12/1/2018

Version 23 Henderson Municipal Power & Light entering MISO as an

LBA and Transmission Owner and AEP Indiana Michigan

Transmission Company, Inc. entering as a Transmission

Owner.

3/1/2019


Table of Contents

Introduction .............................................................................................................. 6

A. Responsibilities – Authorization ....................................................................... 7

B. Responsibilities – Delegation of Tasks ............................................................ 8

C. Common Tasks for Next-Day and Current-Day Operations ............................ 9

D. Next-Day Operations ........................................................................................ 12

E. Current-Day Operations ................................................................................... 14

F. Emergency Operations .................................................................................... 18

G. System Restoration ......................................................................................... 19

H. Coordination Agreements and Data Sharing ................................................. 20

I. Facility ................................................................................................................ 21

J. Staffing .............................................................................................................. 23

Appendix A ............................................................................................................. 25

Appendix B ............................................................................................................. 26

Appendix C ............................................................................................................. 28


Introduction

The North American Electric Reliability Corporation (NERC) requires every Region,

sub-region, or interregional coordinating group to establish a Reliability Coordinator

(RC) to provide the reliability assessment and emergency operations coordination for the

Balancing Authorities (BAs) and Transmission Operators (TOPs) within the Regions and

across the Regional boundaries.

The Midcontinent Independent System Operator (MISO) serves as the RC for its

members, under coordination agreements, and under RC agreements. The MISO RC has

certain defined responsibilities and directs the reliable operation of Bulk Power System

which is, in general, 100 kV facilities and higher. The MISO RC functions associated

with the reliability of the Bulk Power System include review and approval of planned

facility transmission line outages1 & generation outages2 based upon current and

projected system conditions, monitoring of real time loading information and calculating

post-contingent loadings on the transmission system, administering loading relief

procedures, re-dispatch of generation, and ordering curtailment of transactions and/or

load. The MISO RC functions associated with power supply reliability entails monitoring

BA performance and ordering the BAs to take actions, including load curtailment and

increasing/decreasing generation in situations where an imbalance between generation

and load places the system in jeopardy. The MISO reliability procedures and policies are

consistent with NERC Standards.3 MISO operates in multiple NERC Regions and

recognizes each Region’s policies and standards. Where there are conflicts in the

Regional policies and standards, MISO works with the Regions and members on

resolving those conflicts. MISO also provides RC Services for non-market members via

Module F.

This document is the Reliability Plan for the MISO RC and is posted at

https://www.nerc.com/comm/OC/Pages/ORS/Reliability-Plans.aspx. This version

supersedes the previous version.

1 For those Non-market members within MRO, MISO reviews all planned facility transmission line outages for these entities,

notifies the entities of possible conflicts or system conditions that would warrant reconsideration of these planned outages, and

works with the entities – along with MISO members - to resolve any issues. Further revisions of NERC Standards may render

this distinction obsolete.

2 MISO discusses and coordinates pending generation maintenance outages to the extent possible, as MISO has authority to deny

generation maintenance outages only in cases where such outages would place MISO in an emergency situation.

3 While the MISO Reliability Coordination Plan describes MISO’s general practices of providing RC services and in some

circumstances MISO RC’s endeavor to use best practices beyond what is required by the NERC Reliability Standards , Nothing

in this plan shall require MISO RC to go beyond what is required by the NERC Reliability Standards with regard to meeting

NERC compliance requirements.

https://www.nerc.com/comm/OC/Pages/ORS/Reliability-Plans.aspx

___________________________________________________________________________________________


A. Responsibilities – Authorization

1. Reliable Operations - MISO has certain defined responsibilities for the reliable operation of the Bulk

Power System within the its RC Area in accordance with NERC Standards, Regional policies and

standards, as well as the governing documents listed in Appendix C of this document. The MISO

RC Area is composed of the Transmission Owners’ Areas listed in Appendix A.

1.1 The MISO RC has a Wide Area view of its RC Area and neighboring areas that have an impact

on MISO’s Area. The MISO RC and MISO BA have the operating tools, processes and

procedures, including the authority, to prevent or mitigate emergency operating situations in both

next-day analysis and during real-time conditions per the NERC Standards and Regional

standards, as well as the governing documents listed in Appendix C of this document.

The MISO RC operating tools, which provide the Wide Area View, are listed in Section I.

1.2 The MISO RC has clear decision-making authority to act and to direct actions to be taken by its

members and non-MISO members within its Reliability Coordination Area to preserve the

integrity and reliability of the Bulk Power System.

1.3 The MISO RC and the MISO BA have not delegated any of its RC or BA responsibilities.

2. Independence - MISO does and will act first and foremost in the best interest of the reliability for its

RC Area and the Eastern Interconnection before that of any other entity. This expectation is clearly

identified in the governing documents listed in Appendix C and in the job descriptions of the MISO

personnel acting in the role of RC or BA.

3. MISO RC Operating Instructions Compliance - Per the governing documents in Appendix C, the

BAs, TOPs and other operating entities in the MISO RC Area shall carry out required emergency

actions as given in operating instructions by the MISO RC, including the shedding of firm load if

required, except in cases involving endangerment to the safety of employees or the public. In those

cases, members of the MISO RC Area must immediately inform the MISO RC of the inability to

perform the operating instruction.

___________________________________________________________________________________________


B. Responsibilities – Delegation of Tasks

1. The MISO RC and the MISO BA have not delegated any RC or BA tasks. Local Balancing

Authorities (LBAs) within the MISO Balancing Area are responsible for and will perform tasks per

the MISO BA/LBA Coordinated Functional Registration with NERC and the MISO Amended BA

Agreement.

___________________________________________________________________________________________


C. Common Tasks for Next-Day and Current-Day Operations

This section documents how the MISO conducts current-day and next-day reliability analysis for its

Reliability Coordination Area.

1. Determination of Interconnection Reliability Operating Limits (IROLs) – The MISO RC determines

IROLs based on local, regional and inter-regional studies including seasonal assessments and ad hoc

studies. As required, the voltage stability IROLs are calculated in the next day security analysis and

limits are conveyed to neighboring RCs and TOPs in the MISO RC Area via the next day security

analysis report. The IROL limits are also reviewed each weekday morning during reliability

conference calls.

During the operating day, real time voltage stability analyses are performed to provide updated

IROLs, based on the latest system conditions, to the MISO RC. Significant IROL changes are

communicated to impacted TOPs in the MISO RC Area and neighboring RCs by email and phone as

necessary. Standing IROL interfaces are highlighted in bold in MISO operator displays to

differentiate them from System Operating Limit (SOL) flowgates.

During real time operations, the MISO RC recognizes that a new IROL limit can be created during

multiple, normally non-critical outage conditions and the MISO RC determines additional IROLs

real-time. To determine these additional IROLs, the MISO RC utilizes a state estimator and real time

contingency analysis to analyze real-time and first contingency conditions. These contingency

analyses are normally repeated every one to two minutes. In the event a first contingency would

cause a post-contingency flow of 125% of the emergency rating, it is automatically assumed the

SOL is now an IROL unless there are studies or system knowledge that the SOL is not an IROL. An

example of an SOL greater than 125% that would not be considered an IROL is a radial system that

would not result in uncontrolled cascading or collapse should the monitored element(s) trip.

Contingency analysis results indicating an unsolved contingency which is confirmed to be valid is

also considered to be an IROL.

2. Operation to prevent the likelihood of a SOL or IROL exceedance in another area of the

Interconnection and operation when there is a difference in limits - The MISO RC, through

agreements with its RC neighbors, coordinates operations to prevent the likelihood of an SOL or

IROL exceedance in another area. These agreements include data exchange, Available Transfer

Capability coordination, and Outage Coordination and are listed in Section H.

TOPs in the MISO RC Area are required to follow operating instructions provided by the MISO RC

per NERC Standards and operate to NERC Standards to prevent the likelihood that a disturbance,

action, or non-action in its Reliability Coordination Area will result in an SOL or IROL exceedance

in another area of the Interconnection.

When there is a difference in derived limits, MISO RC utilizes the most conservative limit until the

difference is resolved.

3. Operation under known and studied conditions and re-posturing without delay and no longer than 30

minutes - The MISO RC ensures that entities within its RC Area always operate under known and

___________________________________________________________________________________________


studied conditions and that they return their systems to a secure operating state following

contingency events within approved timelines, regardless of the number of contingency events that

occur or the status of their monitoring, operating and analysis tools. The MISO RC also ensures its

BAs and TOPs re-posture the system to within all IROLs following contingencies within Tv or 30

minutes, whichever is shorter.

On a daily basis, the MISO RC conducts next-day security analysis utilizing planned outages,

forecasted loads, generation commitment, and expected net interchange. The analyses include

contingency analysis, voltage stability analysis on key interfaces and a review of reactive reserves

for defined areas when appropriate. These analyses model peak conditions for the day and are

conducted utilizing first contingency (N-1) analysis. Results and mitigation are documented in the

Next-Day Security Analysis Report and distributed to MISO Reliability staff. The Next-Day

Security Analysis Report is also posted on the MISO Extranet secure website for distribution from

this secure website for TOPs and BAs in the MISO Reliability Coordination Area and neighbors to

view and download. Mitigation plans are formed as needed for potential exceedances determined in

the next day security analysis. Mitigation is of the form of additional unit commitment or may be

documented in an operating guide to be utilized by the MISO RC and TOP.

MISO performs Current Day Security Analysis studies in the operating day for morning, peak or

near-peak and minimum load periods. The voltage stability analyses are also performed continuously

and on demand as system conditions warrant for each voltage stability flowgate. Current Day

analysis is documented in the MISO Current Day Security Analysis Report that is distributed to

MISO Reliability staff, and analysis data is posted to the MISO Extranet for the TOPs and BAs in

the MISO Reliability Coordination Area and neighbors.

The MISO Daily Reliability Coordination Report is also posted on the MISO Extranet secure web

site for TOPs and BAs in the MISO Reliability Coordination Area and neighbors to view and

download. The MISO Daily Reliability Coordination Report includes significant generation

outages, significant line outages, projected constraints, voltage security assessment results, reactive

reserves for defined areas when appropriate, TLR summary from the past 24 hours, and forecasted

weather conditions. The MISO Daily Reliability Coordination Report is reviewed each weekday

morning with TOPs, the MISO BA, Balancing Areas in the MISO Reliability Coordination Area,

and neighboring RCs where expected system conditions for the day are discussed, along with action

required to mitigate any abnormal conditions. Additional conference calls are conducted with the

same group when conditions warrant.

4. Communicating SOLs and IROLs to Transmission Service providers within RC Area – MISO

communicates IROLs within its wide-area view and provides updates to IROLs as described above

via reports, morning conference calls, and real-time via voice and messaging. Standing IROLs are

documented and communicated via operating guides. In general, SOLs are in the form of thermal

equipment limits and are provided by Transmission Owners to MISO. If transmission service is sold

on the IROL or SOL Flowgate, an adjustment is made to the AFC to account for the reservation.

5. MISO RC and BA process for issuing operating instructions - MISO has implemented a

communication protocol for the issuing/receiving of operating instructions. The MISO RC and/or

MISO BA issues operating instructions in a clear, concise and definitive manner. The MISO RC

and/or MISO BA ensures that the person receiving the operating instruction repeats the information

back correctly, and acknowledges the response as correct or repeats the original statement again to

___________________________________________________________________________________________


resolve any misunderstandings. MISO’s process for issuing operating instructions is documented in

the “Communications Protocol For Operating Instructions” procedure.

___________________________________________________________________________________________


D. Next-Day Operations

This section documents how the MISO conducts next-day reliability analysis for its Reliability

Coordination Area.

1. Reliability Analysis and System Studies - The MISO RC conducts next-day reliability analyses for

its Area to ensure that the Bulk Power System can be operated reliably in normal and post

contingency conditions.

On a daily basis, the MISO RC conducts next-day security analysis utilizing known outages,

forecasted loads, generation commitment and dispatch, and expected net interchange. All facilities

100 kV and above and some non-BES facilities in the MISO RC Area and first tier Balancing Areas

are monitored for all contingency cases and the base case. Base case flows on all monitored

facilities are compared against the normal rating. Post-contingent flows for all monitored facilities

are compared against their emergency rating for all contingencies. Voltage and transient stability

analysis is conducted on key critical interfaces to determine a flow limit. Reactive reserves for

specific areas are reviewed to ensure they are above necessary levels.

Mitigation plans are formed as needed for potential violations determined in the next day security

analysis. Mitigation is of the form of additional unit commitment, restriction on unit output, or may

be documented in an operating guide to be utilized by the MISO RC and TOPs.

1.1 Parallel Flows – The MISO RC monitors parallel flows to ensure that its Reliability Coordination

Area does not burden another Reliability Coordination Area. To ensure that the impact of

parallel flows is considered in the next day security analysis, all first tier BA Areas and key

second and third tier BA Areas are modeled in detail and updated in the analysis each day. This

includes updating their unit status, transmission outages, load forecast, interchange and

generation dispatch.

2. Information Sharing – BAs, Generation Operators and TOPs in the MISO Reliability Coordination

Area and neighboring RCs provide to the MISO RC all information required for system studies, such

as critical facility status, load, generation, and Operating Reserve projections via the SDX. The

entities in the MISO Reliability Coordination Area provide generation and transmission facility

statuses to the MISO outage scheduling application per MISO outage scheduling requirements.

MISO Reliability Coordination Area load forecast is provided in the SDX. MISO BA load is

determined by MISO load forecasting tools. Known interchange transactions are provided as NERC

E-Tags. MISO obtains the equivalent information for entities outside the MISO Reliability

Coordination Area from the SDX and NERC E-Tags.

3. Sharing of Study Results - When conditions warrant or upon request, the MISO RC shares the

results of its system studies with the entities within its Reliability Coordination Area or with other

RCs. Study results for the next day typically are available no later than 16:00 Eastern Standard Time,

unless circumstances warrant otherwise.

Next-Day Security Analysis Report is distributed to MISO Reliability staff. The Next-Day Security

Analysis Report is also posted on the MISO Extranet secure website for distribution to TOPs and

___________________________________________________________________________________________


BAs in the MISO Reliability Coordination Area and neighboring RCs to view and download. Any

reliability entity that is subject to the NERC Data Confidentiality Agreement may access the Next-

Day Security Analysis Report, with approved access, via the MISO Extranet secure web site.

The MISO RC has procedures indicating when it will initiate a conference call or other appropriate

communications to address the results of its reliability analyses. The MISO RC hosts a conference

call each business day that is normally utilized for this purpose.

___________________________________________________________________________________________


E. Current-Day Operations

This section documents how the MISO conducts current-day reliability analysis for its Reliability

Coordination Area.

1. The process MISO RC uses to monitor all Bulk Power System facilities, including sub-transmission

information as needed, within the MISO Reliability Coordination Area and adjacent areas as

necessary to ensure that, at any time, regardless of prior planned or unplanned events, the MISO RC

is able to determine any potential SOL and IROL exceedances within its Reliability Coordination

Area is as follows:

MISO RC utilizes a state estimator and real-time contingency analysis as its primary tool to monitor

facilities. The state estimator model includes all facilities 100 kV and above in the MISO Reliability

Coordination Area and extensive representation of 69 kV facilities. The model also has extensive

representation of neighboring facilities in order to provide an effective wide-area view. This model

is updated quarterly and may be updated on demand when deemed necessary.

Real Time Contingency Analysis (RTCA) is performed on over 10,000 contingencies utilizing the

state estimator model normally at least every five minutes. Contingencies include all MISO

Reliability Coordination Area equipment 100 kV and above, some non-BES equipment, and

neighboring contingencies that would impact MISO Reliability Coordination Area facilities.

MISO utilizes a Real-Time Line Outage Distribution Factor (RTLODF) Tool to monitor selected

PTDF and OTDF flowgates to provide a backup to RTCA monitoring. Post-contingent loading on

OTDF flowgates is calculated using SCADA data and LODFs automatically updated from a

topology processor that does not rely on the state estimator solution.

SCADA alarming is utilized to alert the MISO RC of any actual low or high voltages or facilities

loaded beyond their normal or emergency limits.

In addition to the above applications, MISO utilizes a dynamically updated transmission overview

display to maintain a wide area view. Transmission facilities 230 kV and above are depicted on the

overview with flows (MW and MVAR). This display provides indication of facilities out of service,

high and low voltage warning and alarming, and facilities loaded to 90% and 100% of ratings. For

more detailed monitoring, dynamically updated Balancing Area wide displays are used to view

facilities 100 kV and above, including flows (MW and MVAR), voltages, generator outputs, and

facilities out of service. Finally, bus level one-line diagrams are utilized for station level information.

1.1. The MISO RC notifies neighboring RCs of operational concerns (e.g. declining voltages,

excessive reactive flows, or an IROL exceedance) that it identifies within the neighboring

Reliability Coordination Area via direct phone calls, conference calls, NERC hotline calls,

and/or RCIS messages. The MISO RC has documented seams agreements with neighboring

RCs that are listed in Section H. MISO RC directs action to provide emergency assistance to

all Reliability Coordination neighbors, during declared emergencies, which is required to

mitigate the operational concern to the extent that the same entities are taking in kind steps

and the assistance would be effective.

___________________________________________________________________________________________


2. The MISO RC maintains awareness of the status of all current critical facilities whose failure,

degradation or disconnection could result in an SOL or IROL exceedance within its Reliability

Coordination Area via State Estimator, RTCA, SCADA alarming, and transmission displays. The

MISO RC is aware of the status of any facilities that may be required to assist Reliability

Coordination Area restoration objectives via these same displays and tools.

3. The MISO RC is continuously aware of conditions within its Reliability Coordination Area includes

this information in its reliability assessments via automatic updates to the state estimator, Flowgate

Monitoring Tool, and transmission displays. The MISO RC monitors its MISO Reliability

Coordination Area parameters, including the following:

3.1. Current status of Bulk Power System elements (transmission or generation including critical

auxiliaries such as Automatic Voltage Regulators and Special Protection Systems and system

loading are monitored by state estimator, RTCA, SCADA Alarming, Flowgate Monitoring

Tool, and transmission displays. Balancing Areas are required to report to MISO RC when

Automatic Voltage Regulators are not in-service. TOPs are required to report to the MISO

RC when Special Protection Systems change status.

3.2. Current pre-CONTINGENCY element conditions (voltage, thermal, or stability) are monitored

by state estimator, SCADA Alarming, Flowgate Monitoring Tool, and transmission displays.

3.3. Current post-CONTINGENCY element conditions (voltage, thermal, or stability) are monitored

by RTCA, Flowgate Monitoring Tool, and transmission displays.

3.4. System real reserves are monitored versus required per Balancing Area in the Market

Monitoring Tool. Reactive reserves versus required are monitored via monitoring adequacy

of calculated post-contingent steady state voltages versus voltage limits, voltage stability

interfaces against limits, and reactive reserves versus required for defined zones.

3.5. Capacity and energy adequacy conditions via monitoring reserve requirements and regional

reporting.

3.6. Current ACE for all Balancing Areas is displayed in a trend graph to MISO RC. When ACE

exceeds L10, graph changes colors and alerts operator of magnitude of ACE and duration

ACE has exceeded L10 .

3.7. Current local procedures, such as operating guides, monitored via discussions with local TOP

and statuses of their use are logged in the MISO RC log. TLR procedures in effect are

monitored via the NERC Interchange Distribution Calculator.

3.8. Planned generation dispatches for MISO market area are provided to the MISO RC in the

form of the unit commitment plan. For the non-market area, generation outages are reported

to MISO via the MISO Outage Scheduler application.

3.9. Planned transmission or generation outages are reported to MISO via the MISO Outage

Scheduler application.

___________________________________________________________________________________________


3.10. Contingency Events are monitored by state estimator, RTCA, SCADA Alarming, Flowgate

Monitoring Tool, and transmission displays. TOPs and BAs are required to report

Contingency Events to MISO RC.

4. The MISO RC monitors Bulk Power System parameters that may have significant impacts upon its

Reliability Coordination Area and neighboring Reliability Coordination areas with respect to:

4.1. The MISO RC maintains awareness of all Interchange Transactions that wheel-through,

source, or sink in its Reliability Coordination via NERC E-tags and NERC IDC displays.

Interchange Transaction information is made available to all RCs via NERC E-tags.

4.2. The MISO RC, in concert with the Balancing and Interchange Authorities within its

Reliability Coordination Area, evaluates and assesses any additional Interchange

Transactions that would exceed IROL or SOLs by using the NERC IDC as a look-ahead tool.

As flows approach their IROL or SOLs, the MISO RC evaluates the incremental loading

next-hour transactions would have on the SOLs or IROLs and determines if action needs to

be taken to prevent an SOL or IROL exceedance. The MISO RC has the authority to direct

all actions necessary and may utilize all resources to address a potential or actual IROL

exceedance up to and including load shedding.

4.3. The MISO RC and MISO BA monitors Balancing Area Operating Reserves versus required

to ensure the required amount of Operating Reserves are provided and available as required

to meet NERC Control Performance Standards via the Market Monitoring Tool. The MISO

RC and the MISO BA are alerted if reserves fall below required. If necessary, the MISO RC

will direct the Balancing Area to replenish reserves including obtaining assistance from

neighbors as needed.

4.4. The MISO RC identifies the cause of potential or actual SOL or IROL exceedances via

analysis of state estimator results, RTCA results, SCADA Alarming of outages, Flowgate

Monitoring Tool results, transmission displays of changes, and Interchange Transaction

impacts. The MISO RC will initiate control actions including transmission switching,

generation redispatch, and/or emergency procedures to relieve the potential or actual IROL

exceedance without delay, and no longer than 30 minutes. The MISO RC is authorized to

direct utilization of all resources, including load shedding, to address a potential or actual

IROL exceedance. The MISO RC will not rely solely on NERC TLR to mitigate an IROL

exceedance.

4.5. The MISO RC communicates start and end times for time error corrections to all Balancing

Areas within its Reliability Coordination Area via its messaging system. The MISO RC

communicates Geo-Magnetic Disturbance forecast information to BAs, TOPs, and

Generation Operators via its messaging system. MISO RC will assist in development of any

required response plan and will establish an Emergency Operating Guide as needed or move

to conservative operating mode to mitigate impacts as needed.

___________________________________________________________________________________________


4.6. The MISO RC (Carmel, Eagan, and Little Rock locations) participates in NERC Hotline

discussions, assist in the assessment of reliability of the Regions and the overall

interconnected system, and coordinate actions in anticipated or actual emergency situations.

The MISO RC will disseminate this information via text messaging, individual phone calls,

or blast calls within its area as appropriate.

4.7. The MISO RC monitors system frequency via trend graph. The graph visually alerts the

MISO RC when frequency falls below 59.95 Hz or is greater than 60.05 Hz. MISO BA

monitors its ACE, while the MISO RC monitors each Balancing Area’s ACE via trend graph

within the Reliability Coordination Area. Both the MISO BA and the MISO RC receive a

visual indication when ACE exceeds L10 and/or BAAL. When necessary, MISO RC directs

Balancing Areas with ACEs larger than L10 to return within L10, and directs Balancing Areas

to return to within BAAL. The MISO RC will direct BAs to utilize all resources, including

firm load shedding, as necessary to relieve an emergency condition.

4.8. The MISO RC coordinates with other RCs and its BAs, Generation Operators, and TOPs, as

needed, on the development and implementation of action plans and operating guides to

mitigate potential or actual SOL or IROL exceedances, or CPS1, BAAL, or Reportable

Balancing Contingency Event criteria.. The MISO RC coordinates pending generation and

transmission maintenance outages with other RCs and its BAs, Generation Operators, and

TOPs, as needed and within code of conduct requirements, real time via telephone and next-

day, per the MISO outage scheduling process.

4.9. The MISO RC will assist its BA Areas in arranging for assistance from neighboring RCs or

BA Areas via the Energy Emergency Alert (EEA) notification process and will conference

parties together as appropriate.

4.10. The MISO RC monitors Balancing Areas’ ACEs to identify the sources of large ACEs that

may be contributing to frequency, time error, or inadvertent interchange and directs

corrective actions with the appropriate BAs per 4.7 above.

4.11. The TOPs within MISO Reliability Area inform MISO of all changes in status of Special

Protection Systems (SPS) including any degradation or potential failure to operate as

expected by the TOP. The MISO RC factors these SPS changes into its reliability analyses.

5. The MISO RC issues alerts, as appropriate, to all its Balancing Areas and TOPs via dedicated text

messaging, individual phone calls, or blast calls when it foresees a transmission problem (such as an

SOL or IROL exceedance, loss of reactive reserves, etc.) within its Reliability Area that requires

notification. The MISO RC issues alerts, as appropriate, to all RCs via the Reliability Coordinator

Information System when it foresees a transmission problem (such as an SOL or IROL exceedance,

loss of reactive reserves, etc.) within its Reliability Area that requires notification.

6. The MISO RC confirms reliability assessment results via analyzing results of state estimator/RTCA,

and discussions with local TOPs and neighboring RCs. The MISO RC identifies options to mitigate

potential or actual SOL or IROL exceedances via examining existing operating guides, system

knowledge, and power flow analysis to identify and implement only those actions as necessary as to

always act in the best interests of the interconnection.

___________________________________________________________________________________________


F. Emergency Operations

1. The MISO RC utilizes the MISO Emergency Operating Procedures, posted on the

www.misoenergy.org site, to return the transmission system to within the IROL as soon as possible,

but no longer than 30 minutes. This procedure includes the actions (e.g. reconfiguration, re-dispatch

or load shedding) the MISO RC will direct until relief is achieved.

2. The MISO RC utilizes the MISO Emergency Operating Procedures when it deems that an IROL

exceedance are imminent. The MISO Emergency Operating Procedures documents the processes

and procedures the MISO RC follows when directing its BAs and TOPs to re-dispatch generation,

reconfigure transmission, manage Interchange Transactions, or reduce system demand to mitigate

the IROL exceedance, to return the system to a reliable state. The MISO RC coordinates its alert

and emergency procedures with other RCs via seam coordination agreements listed in Section H.

3. The MISO RC takes or directs action in the event the loading of transmission facilities progresses to

or is projected to progress to an SOL or IROL exceedance.

3.1 The MISO RC directs reconfiguration and/or re-dispatches within its market area as needed to

prevent or relieve SOL or IROL exceedances. In the non-market area of MISO Reliability

Coordination Area, the MISO RC will direct reconfiguration and re-dispatch to resolve IROL

exceedances. The MISO RC will not rely on or wait for NERC TLR to relieve IROL

exceedances. The MISO RC may implement NERC TLR if doing so will provide additional

relief.

3.2 The MISO RC utilizes market-to-market re-dispatch for its market area for reciprocally

coordinated flowgates per the Congestion Management Process posted on the

www.misoenergy.org site and filed with FERC.

3.3 The MISO RC acknowledges provisions of the NERC TLR and communicates curtailment

information as appropriate to impacted Balancing Authorities.

3.4 The MISO RC will initiate re-configuration, re-dispatch for market areas, and NERC TLR

reductions to relieve overloaded facilities as necessary. The MISO RC will not rely on NERC

TLR as an emergency action.

4. The MISO RC utilizes the MISO Emergency Operating Procedures to mitigate an energy emergency

within its Reliability Coordination Area. The MISO RC will provide assistance to other RCs per its

seams agreements listed in Section H.

5. The MISO RC utilizes the MISO Emergency Operating Procedures when it is experiencing a

potential or actual Energy Emergency within any BA, Reserve-Sharing Group, or Load-Serving

Entity within its Reliability Coordination Area. The MISO Emergency Operating Procedures

document the processes and procedures the MISO RC uses to mitigate the emergency condition,

including a request for emergency assistance if required.

___________________________________________________________________________________________


G. System Restoration

1. Knowledge of members’ Restoration Plans - The MISO RC is aware of each member’s Restoration

Plan and has a written copy of each plan. The MISO has the plans and procedures of every member,

which are listed in Appendix A.

During system restoration, MISO RC monitors restoration progress and acts to coordinate any

needed assistance.

2. MISO Restoration Plan - The MISO Restoration Plan includes all BAs and TOPs in its Reliability

Coordination Areas. MISO RC takes action to restore normal operations once an operating

emergency has been mitigated in accordance with its Restoration Plan. This Restoration Plan is

drilled at least annually.

3. Dissemination of Information - The MISO RC serves as the primary contact for disseminating

information regarding restoration to neighboring RCs and members not immediately involved in

restoration.

The MISO RC approves, communicates and coordinates the re-synchronizing of major system

islands or synchronizing points so as not to cause a burden on member or adjacent Reliability

Coordination Areas.

___________________________________________________________________________________________


H. Adjacent RC Agreements and Data Sharing

1. Coordination Agreements:

MISO and PJM have a Joint Operation Agreement

MISO and TVA have a RC Coordination and Notification Plan

MISO and IESO have a Coordination Agreement.

MISO and SPP have a Joint Operating Agreement.

MISO and Southeastern RC have a RC Coordination and Notification Plan.

MISO and SaskPower have a RC to RC Agreement.

2. Data Sharing - The MISO RC determines the data requirements to support its reliability coordination

tasks and requests such data from members or adjacent RCs. The MISO RC provides for data

exchange with members and adjacent RCs, TOPs and BAs via a secure network. MISO Reliability

Coordination Area members provide data to MISO via ICCP. MISO RC provides data to entities

outside MISO via direct links and ISN.

___________________________________________________________________________________________


I. Facility

MISO performs the RC function at the MISO Headquarters in Carmel, Indiana along with the MISO

offices in Eagan, Minnesota, and Little Rock, Arkansas. The Carmel, Eagan, and Little Rock offices

have the necessary voice and data communication links to appropriate entities within their Reliability

Coordination Area for the MISO RC to perform their responsibilities. These communication facilities

are staffed and available to act in addressing a real-time emergency condition.

1. Adequate Communication Links - The MISO RC maintains satellite phones, Voice Over IP phones

which run across the dedicated MISO WAN, cell phones, and redundant, diversely routed

telecommunications circuits. Additionally, there are also video links between MISO Carmel Control

Room and the MISO Eagan and Little Rock Control Rooms.

2. Multi-directional Capabilities – The MISO RC has multi-directional communications capabilities

with its members, and with neighboring RCs, for both voice and data exchange to meet reliability

needs of the Interconnection.

3. Real-time Monitoring - The MISO RC has detailed real-time monitoring capability of its Reliability

Coordination Area and all first tier companies surrounding the MISO Reliability Coordination Area

to ensure that potential or actual System Operating Limit or Interconnection Reliability Operating

Limit exceedances are identified.

3.1 The MISO RC monitors Bulk Power System elements (generators, transmission lines, buses,

transformers, breakers, etc.) that could result in SOL or IROL exceedances within its Reliability

Coordination Area. The MISO RC monitors both real and reactive power system flows, and

operating reserves, and the status of the Bulk Power System elements that are, or could be,

critical to SOLs and IROLs and system restoration requirements within its Reliability

Coordination Area.

4. Study and Analysis Tools

4.1 The MISO RC has adequate analysis tools, including state estimation, pre-and post-contingency

analysis capabilities (thermal, stability, and voltage), and wide-area overview displays. The

MISO RC has detailed monitoring capability of the MISO Reliability Area and sufficient

monitoring capability of the surrounding Reliability Areas to ensure potential reliability issues

are identified. The MISO RC continuously monitors key transmission facilities in its area in

conjunction with the Members monitoring of local facilities and issues.

The MISO RC ensures that SOL and IROL monitoring and derivations continue if the main

monitoring system is unavailable. The MISO RC has backup facilities that shall be exercised if

the main monitoring system is unavailable.

___________________________________________________________________________________________


The systems utilized by the MISO RC are:

State Estimator and Contingency Analysis

Market Monitoring Tool

Status and Analog Alarming

Overview Displays of MISO Transmission System via Wallboard

One line diagrams for entire MISO Transmission System

Transmission Delta Flow Tool

Flowgate Monitoring Tool

Generation Monitoring Tool

The MISO RC utilizes these tools, which provide information that is easily understood and

interpreted by the MISO RC operating personnel. The alarm management is designed to classify

alarms in priority for heightened awareness of critical alarms.

4.2 The MISO RC controls its RC analysis tools, including approvals for planned maintenance. The

MISO RC has procedures in place to mitigate the effects of analysis tool outages.

___________________________________________________________________________________________


J. Staffing

1. Staff Adequately Trained and NERC Certified - MISO maintains trained RCs, BAOs, and a Shift

Manager on duty at all times, as well shift Reliability Engineers. The MISO RC and MISO BA staff

all operating positions that meet following criteria with personnel that are NERC certified for the

applicable functions:

Positions that have the primary responsibility, either directly or through communications with

others, for the real-time operation of the interconnected Bulk Power System.

Positions directly responsible for complying with NERC Standards.

The MISO RC and MISO BA operating personnel each complete a minimum of 40 hours per year of

training and drills using realistic simulations of system emergencies, in addition to other training

required to maintain qualified operation personnel.

2. Comprehensive Understanding - The MISO RC operating personnel have an extensive

understanding of the BAs and TOPs within the MISO Reliability Coordination Area, including the

operating staff, operating practices and procedures, restoration priorities and objectives, outage

plans, equipment capabilities, and operational restrictions.

The MISO RC operating personnel place particular attention on SOLs and IROLs and inter-tie

facility limits. The MISO ensures protocols are in place to allow MISO RC operating personnel to

have the best available information at all times.

MISO’s System Operator Training process describes the process by which System Operations

personnel are trained to perform their duties, both at entry level and in continuous training status.

MISO also uses the Operator Training Manual to establish training and documentation requirements

for System Operators in the form of position specific curricula, NERC certification Guidelines, On-

the-Job qualification Guides, and Technical Qualification Training Checklists. The Technical

Qualification Training Checklists contain competencies for the RC System Operator position and

other operation positions. An analysis of each operator position was conducted by Subject Matter

Experts (SME), Management, and training representatives to develop the checklists. These checklists

provide a way to identify, track status, and document completion of required initial training for any

new System Operator.

MISO uses several means to provide initial and continuous training opportunities for System

Operators. MISO Operations Technical Training provides the majority of the technical training.

MISO Corporate Training provides much of the corporate and non-technical courses such as

Standards of Conduct, Fitness for Duty, Ethics and Employee Conducts and Disciplinary Guidelines.

Information Technology (IT) Education conducts training on computer-based applications such as

Word, Excel, Access Database, etc. Continuing training is designed to keep all operating personnel

knowledgeable of current policies, equipment and management expectations. Drills on emergency

procedures and simulated exercises are included in the on-going training activities. Training records

are maintained.

___________________________________________________________________________________________


3. Standards of Conduct - MISO RC and MISO BA are independent of the merchant function. RC and

BA Operators do not pass information or data to any wholesale merchant function or retail merchant

function that is not made available as soon as practicable to all such wholesale merchant functions.

MISO RC and MISO BA staff have completed training on MISO’s Standards of Conduct. Refresher

training on MISO’s Standards of Conduct is conducted every year. Training records are maintained.

___________________________________________________________________________________________


Appendix A

List of Transmission Owners within the MISO Reliability Coordination Area & the documents associated with each:

MISO Members MISO Authority Documents

MISO TO

Agreement

MISO Tariff Coordination

Agreement

RC Services

Agreement

Appendix I

AEP Indiana Michigan Transmission

Company, Inc. X X

AmerenCILCO X X

AmerenIP X X

AmerenUE and AmerenCIPS X X

American Transmission Company, LLC X X

Arkansas Electric Cooperative Corporation X X

Big Rivers Electric Corporation X X

CLECO X X

Central Minnesota Municipal Power Agency X X

City of Alexandria (LA) X X

City of Ames X X

City of Marshall (MN) X X

Dairyland Power Cooperative X X

Duke Energy Indiana, Inc. X X

East Texas Electric Cooperative, Inc X X

Entergy Arkansas, Inc. X X

Entergy Gulf States Louisiana, L.L.C. X X

Entergy Louisiana, LLC X X

Entergy Mississippi Inc. X X

Entergy New Orleans, Inc X X

Entergy Texas, Inc. X X

Cedar Falls Utilities X X

City of Columbia, MO X X

City Water, Light & Power (Springfield, IL) X X

Great River Energy X X

Henderson Municipal Power & Light X X

Hoosier Energy Rural Electric Cooperative X X

Indiana Municipal Power Agency X X

Indianapolis Power and Light X X

Lafayette Utility System X X

Louisiana Energy and Power Authority X X

Louisiana Generating X X

Michigan Electric Transmission Co, LLC X X

Michigan Public Power Agency X X

Michigan South Central Power Agency X X

MidAmerican Energy Company X X

Minnesota Power, Inc and subsidiary X X

Minnesota Municipal Power Agency X X

Missouri River Energy Services X X

Muscatine Power and Water X X

Montana-Dakota Utilities Co. X X

Northern Indiana Public Service Company X X

Northwestern Wisconsin Electric Company X X

Otter Tail Power Company X X

___________________________________________________________________________________________


Pioneer Transmission X X

Prairie Power X X

Rochester Public Utilities X X

Cooperative Energy X X

Southern Illinois Power Cooperative X X

Southern Minnesota Municipal Power Agency X X

Vectren for Southern Indiana Gas & Electric X X

Wabash Valley Power Association, Inc. X X

Wolverine Power Supply Cooperative, Inc. X X

Xcel Energy, Inc. X X

Manitoba Hydro X

International Transmission Company X

Non-MISO Members

American Electric Power Company X

Consumers Energy X

Lansing Board of Water and Light X

Minnkota Power Cooperative X

NorthWestern Energy X

Appendix B

Balancing Areas within the MISO Reliability Coordination Area

Balancing Area Name Balancing

Area

Local

BA

within

MISO

BA

Under

MISO

Tariff

Reliability

Coordination

Office

Carmel,

IN

Eagan,

MN

Little

Rock,

AR

0 Midcontinent ISO MISO - Yes X X X

1 Alliant Energy - CA - ALTE ALTE Yes Yes X

2 Alliant Energy - CA - ALTW ALTW Yes Yes X

3 Ameren Illinois AMIL Yes Yes X

4 Ameren Missouri AMMO Yes Yes X

5 Big Rivers Electric Corporation BREC Yes Yes X

6 Duke Energy CIN Yes Yes X

7 City Water Light & Power CWLP Yes Yes X

8 Columbia Water & Light CWLD Yes Yes X

9 Consumers Energy Company CONS Yes Yes X

10 Dairyland Power Cooperative DPC Yes Yes X

11 Detroit Edison Company DECO Yes Yes X

12 Entergy Arkansas EAI Yes Yes X

13 Entergy Electric System EES Yes Yes X

14 Entergy Mississippi EMBA Yes Yes X

15 Great River Energy GRE Yes Yes X

16 Henderson Municipal Power & Light HMPL Yes Yes X

16

17

Hoosier Energy HE Yes Yes X

17

18

Indianapolis Power & Light Company IPL Yes Yes X

18

19

MidAmerican Energy Company MEC Yes Yes X

___________________________________________________________________________________________


19

20

Madison Gas and Electric Company MGE Yes Yes X

20

21

Michigan Electric Coordinated System MECS Yes Yes X

21

22

Michigan Upper Peninsula MIUP Yes Yes X

22

23

MHEB, Transmission Services MHEB No No X

23

24

Minnesota Power, Inc. MP Yes Yes X

24

25

Montana-Dakota Utilities Co. MDU Yes Yes X

25

26

Muscatine Power and Water MPW Yes Yes X

26

27

Northern Indiana Public Service Company NIPS Yes Yes X

27

28

Northern States Power Company NSP Yes Yes X

28

29

Otter Tail Power Company OTP Yes Yes X

29

30

Southern Indiana Gas & Electric Co. SIGE Yes Yes X

30

31

Southern Illinois Power Cooperative SIPC Yes Yes X

31

32

Southern Minnesota Municipal Power Agency SMP Yes Yes X

32

33

Upper Peninsula Power Co. UPPC Yes Yes X

33

34

Wisconsin Energy Corporation WEC Yes Yes X

34

35

Wisconsin Public Service Corporation WPS Yes Yes X

35

36 CLECO CLECO Yes Yes X

36

37 Lafayette Utility System LAFA Yes Yes X

37

38 Louisiana Energy and Power Authority LEPA Yes Yes X

38

39 Louisiana Generating LAGN Yes Yes X

39

40 Cooperative Energy SME Yes Yes X

___________________________________________________________________________________________


Appendix C

Responsibilities and Authorities

The following lists the responsibilities/authorities of the MISO and the documents where those

responsibilities/authorities are defined.

MISO Responsibilities / Authorities

Document Responsibilities / Authorities MISO Transmission Owner Agreement Security and Reliability of the Transmission

System


Take emergency action – including shedding load

MISO Tariff Curtailment of transmission service

Coordination Agreement Security and Reliability of the Transmission

System


Interconnection Agreements Agreement between Transmission Owners and

Generation Owners

Appendix “I” Security and Reliability of the Transmission

System

Outage coordination for independent transmission

Companies (ITC, METC)

RC Agreement Provide Reliability Coordination Services

Agreement Between Midcontinent ISO

and Midcontinent ISO BAs to Implement

TEMT

Agreement between Midcontinent ISO and BAs

that are signatories to the agreement. The

agreement does not apply to non-MISO members.

The agreement delineates the responsibilities

between Midcontinent ISO and the BAs as is

necessary to allow the TEMT, market tariff, to be

implemented.

MISO BA – Local BA Agreements The agreement documents the coordination of the

actions associated with the defined BA

responsibilities

Reliability Coordinator Procedure

Version No. Final

Effective Date 7/1/2019

California ISO Reliability Coordination Plan Distribution Restriction: None

1

California ISO Reliability Coordination Plan

Table of Contents

Introduction ................................................................................................................................. 2

1. Responsibilities – Authorization ........................................................................................... 2

2. Responsibilities – Delegation of Tasks ................................................................................ 3

3. Common Tasks for Next-Day and Current-Day Operations ................................................. 3

4. Next Day Operations ........................................................................................................... 4

5. Current-Day Operations ....................................................................................................... 5

6. Emergency Operations ........................................................................................................ 8

7. System Restoration ............................................................................................................. 9

8. Coordination Agreements and Data Sharing ........................................................................ 9

9. Facility ................................................................................................................................. 9

10. Staffing .............................................................................................................................. 11

11. APPENDIX A – California ISO Governing Documents ....................................................... 12

12. APPENDIX B – Agreements with External Entities ............................................................ 12

13. APPENDIX C - California ISO Reliability Area Map ........................................................... 12

14. APPENDIX D – California ISO Reliability Coordination Procedures ................................... 14


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Introduction

The North American Electric Reliability Corporation (NERC) requires every Region, sub-region, or interregional coordinating group to establish a Reliability Coordinator to provide the reliability assessment and emergency operations coordination for the Balancing Authorities and Transmission Operators within the Regions and across the Regional boundaries.

California ISO Reliability Coordinator (CAISO RC) serves as the reliability coordinator (RC) for its Balancing Authority (BA) customers and the Transmission Operating (TOP) customers in their respective BA Areas. The CAISO RC functions associated with the reliability of the Bulk Electric System (BES) include:

Review and approval of planned facility, transmission line outages and generation outages based upon current and projected system conditions,

Monitoring facilities within its Reliability Coordination Area and neighboring Reliability Coordination areas to identify any System Operating Limit (SOL) exceedances and to determine any Interconnection Reliability Operating Limit (IROL) exceedances within its Reliability coordination area, and

Issuing Operating Instructions to ensure reliability of the BES is maintained.

CAISO RC procedures and policies are consistent with NERC and WECC Regional Reliability Organization (RRO) Standards.

1. Responsibilities – Authorization

1.1. Authority to Act - CAISO RC is responsible for the reliable operation of the BES within its Reliability Coordination Area, in accordance with NERC Standards and Regional policies and standards. CAISO RC’s authority to act is derived from a set of agreements that all CAISO RC members have executed (See Appendices A and C).

1.2. Decision Making Authority - CAISO RC has clear decision-making authority to act and to direct or instruct members within its Reliability Coordination Area to take action to preserve the integrity and reliability of the BES. CAISO RC’s responsibilities and authorities, as well as its members’ responsibilities, are clearly defined in the governing documents.

1.3. Wide Area view of its Reliability Coordination Area - CAISO RC has a Wide Area view of its Reliability Coordination Area and neighboring areas that have an impact on CAISO RC’s area. The CAISO RC has the operating tools, processes and procedures (including the authority) to prevent or mitigate emergency operating situations in both next-day analysis and during real-time conditions, per the NERC Standards and Regional policies and standards, as well as the governing documents listed in Appendix A of this document.

1.4. Independence - CAISO RC will act in the best interest of insuring reliability for its Reliability Coordination Area and the Western Interconnection, before that of any other entity. This expectation is clearly identified in the governing documents (see Appendix A).

1.5. CAISO RC Operating Instruction Compliance - Per the governing documents (see Appendix A), the participating control centers shall carry out required emergency actions as directed or


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instructed by the CAISO RC, including the shedding of firm load if required, unless such actions would violate safety, equipment, regulatory, or statutory requirements.

2. Responsibilities – Delegation of Tasks

2.1. CAISO RC has not delegated any Reliability Coordination tasks.

3. Common Tasks for Next-Day and Current-Day Operations

3.1. This section documents how CAISO RC conducts current-day and next-day reliability analysis for its Reliability Coordination Area.

3.2. Determination of Interconnection Reliability Operating Limits (IROLs) – CAISO RC established IROLs in accordance with its SOL methodology

3.3. During real-time operations, the CAISO RC continuously ensures that the system is resilient and not in danger of cascade failure due to Thermal Cascading (monitored through Real Time Contingency Analysis [RTCA]), Voltage instability (monitored through Voltage Stability Analysis [VSA]) and Dynamic Transient Instability (monitored through Real-Time Dynamic Stability Assessment [RT-DSA]).

3.4. CAISO RC monitors and acts to prevent the likelihood of a SOL or IROL exceedance in its own area or other areas of the Interconnection, and coordinates with impacted Reliability Coordinators when there is a difference in limits. CAISO RC, through the agreements with other Reliability Coordinator neighbors, will coordinate operations to prevent the likelihood of a SOL or IROL in another area. The scope of these agreements includes data exchange and Outage Coordination. (See Appendix B.)

3.5. BA and TOP customer control centers in the CAISO RC Area must follow Operating Instructions provided by CAISO RC. NERC Standards are followed to prevent the likelihood that a disturbance, action, or non-action in its Reliability Coordination Area will result in a SOL or IROL exceedance in its own area or other areas of the Interconnection. When there is a difference in derived limits between RCs, the CAISO RC utilizes the most conservative limit until the difference is resolved.

3.6. Operate under known and studied conditions and reposition without delay and within no longer than 30 minutes following Contingency events or operational situations that require such action – The CAISO RC will perform real-time analysis at least once every 30 minutes. Under normal circumstances, the CAISO RC will perform real-time analysis after every 5 minute RTCA and VSA run, and after every 15 Minute RT-DSA run. This provides assurance that entities within its Reliability Coordination Area always operate under known and studied conditions and that they return their systems to a secure operating state following Contingency events, within approved timelines. CAISO RC also ensures that entities within its Reliability Coordination Area operate the system to be within all IROLs following Contingencies, within 30 minutes.

3.7. On a daily basis, CAISO RC conducts Operations Planning Analysis, factoring in planned outages, forecasted loads, generation commitment, and expected net interchange. The analyses include Contingency analysis and voltage stability analysis on key interfaces.


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These analyses model each operating hour of the day, and include assessment of anticipated (pre-Contingency) and potential (post-Contingency) conditions for next-day operations.

3.8. Results and mitigation are documented in the Day Ahead Reliability Analysis (DARA) report and made available for review, to CAISO RC staff and entities within the CAISO Reliability Coordinator Area and neighboring Reliability Coordinators. Mitigation plans are formed as needed for potential SOL and IROL exceedance determined in the DARA.

3.9. In real-time, CAISO RC relies on its telemetry and real-time analysis tools to monitor the real-time system conditions to identify potential IROL and SOL exceedance. CAISO’s operational philosophy is to monitor and initiate operating plans for all SOL exceedances identified through Real Time Assessment, which include assessment of existing (pre-Contingency) and potential (post-Contingency) operating conditions. CAISO communicates about IROLs within its RC Area and provides updates as needed via reports, morning conference calls, and in real-time, via voice and messaging.

3.10. CAISO process for issuing Operating Instructions – CAISO uses a number of communication tools for issuing/receiving of Operating Instructions. The primary communication means is the CAISO Turret Phone system, which is a dedicated telephone-based system. The CAISO RC will also employ a “Grid Messaging System” that sends instructions/message(s) to all control centers simultaneously, and confirms response. CAISO communicates Operating Instructions in a clear, concise and definitive manner. When appropriate, three-part communication will be required to ensure the communications are correctly received and understood.

4. Next Day Operations

4.1. This section documents how CAISO RC conducts Operational Planning Analysis for its Reliability Coordination Area.

4.2. Reliability Analysis and System Studies – CAISO RC conducts Operational Planning Analysis for its Area to assess anticipated (pre-Contingency) and potential (post-Contingency) conditions for next-day operations, and to ensure that the BES can be operated reliably in normal and post-Contingency conditions.

4.3. On a daily basis, CAISO RC conducts Operational Planning Analysis, utilizing known outages, forecasted loads, generation commitment and dispatch, and expected net interchange, employing the study capability in the CAISO Network Applications. Base case flows on all monitored facilities are compared against the normal continuous rating. Post-Contingency flows for all monitored facilities are compared against their Emergency rating for all Contingencies. Voltage stability analysis is conducted on key critical interfaces to determine stability limit.

4.4. CAISO RC coordinates mitigation plans as needed for potential SOL exceedance determined in the Operational Planning Analysis. Mitigation can include additional generation commitment, system reconfiguration, generation re-dispatch, outage postponement or other local flow mitigation procedures.

4.5. Information Sharing – BAs and TOPs in the CAISO RC Area and neighboring Reliability Coordinator areas provide CAISO RC with all information required for system studies, such


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as critical facility status, load, generation, Contingency Reserve projections and known interchange transactions.

4.6. The entities in the CAISO RC Area provide expected generation and transmission facility status to the CAISO outage scheduling application, including forecasted loads, operating reserves, and known interchange transactions. CAISO RC provides this information through a secure network to applicable members.

4.7. Sharing of Study Results - CAISO RC makes available the results of its system studies with the entities within its Reliability Coordination Area and/or with other Reliability Coordinators. CAISO RC intends to make study results available for the next day by no later than 16:00 Pacific Prevailing time, unless unforeseen circumstances prevent this.

4.8. Day Ahead Reliability Analysis Report (DARA) - Made available to CAISO RC and neighboring Reliability Coordinators. CAISO RC holds daily conference calls as necessary, with participating members and others as part of this process.

5. Current-Day Operations

5.1. This section documents how CAISO RC conducts Real-Time reliability analysis for its Reliability Coordination Area.

5.2. CAISO RC uses a suite of real-time network analysis tools to continuously monitor all BES facilities within the CAISO RC Area and adjacent areas, including sub-transmission information as needed, to ensure that CAISO RC is able to proactively maintain system reliability. CAISO RC makes every effort to prevent any expected or potential SOL and IROL exceedance within its Reliability Coordination Area.

5.3. CAISO RC uses both a state estimator and RTCA as the primary tools to monitor facilities. The state estimator model includes all facilities in the WECC BES, as well as facilities in the CAISO RC Area. The model also includes extensive representation of neighboring facilities, in order to provide an effective wide-area view, and is updated as required to maintain accurate modelling.

5.4. RTCA is performed on Contingencies using the state estimator model approximately every five minutes. Contingencies include all CAISO RC Area equipment and facilities and also any neighboring RC area equipment that is known to impact the CAISO RC area.

5.5. In order to continuously monitor its voltage stability limited interfaces, CAISO RC uses VSA, a real-time calculation tool. VSA takes a state estimator snapshot and calculates a voltage collapse equivalent flow for the interface, based on current real-time telemetry and topology. A VSA Transfer Limit is established as the limit to prevent a potential post-Contingency voltage instability, and CAISO operates to maintain flows below the limit.

5.6. CAISO RC uses SCADA alarming to warn of any actual low or high voltages, or facilities loaded beyond their normal or emergency limits.

5.7. In addition to the above-mentioned applications, CAISO RC uses dynamically updated transmission overview displays to maintain a wide area view. All transmission facilities 220 kV and above are depicted on the overview with flows (MW and MVAR), indication of facilities out of service, high and low voltage warning and alarming. For more detailed monitoring, CAISO RC uses bus level one-line diagrams for station level monitoring and


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information. The one-line diagrams are populated with the real-time telemetered information, as well as the state-estimated solution.

5.8. CAISO RC notifies neighboring Reliability Coordinators of operational concerns (e.g. declining voltages, excessive reactive flows, or IROL exceedance) that it identifies within the neighboring Reliability Coordination Area, via direct phone calls, conference calls, NERC hotline calls, and/or RCIS messages. CAISO RC has joint operating agreements with neighboring Reliability Coordinators (listed in Appendix B) to provide emergency assistance during declared emergencies.

5.9. CAISO RC uses State Estimator, RTCA, SCADA alarming, transmission and summary displays to maintain awareness of the status of all current critical facilities whose failure, degradation or disconnection could result in an SOL or IROL exceedance within its Reliability Coordination Area. These same displays and tools keep CAISO RC informed of the status of any facilities that may be required to assist Reliability Coordination Area restoration objectives.

5.10. CAISO RC is continuously aware of conditions within its Reliability Coordination Area, and includes real-time information in its reliability assessments, via automatic updates to the state estimator, VSA, and transmission displays. CAISO monitors its Reliability Coordination Area parameters, including the following:

5.10.1. Current status of BES elements (transmission or generation including critical auxiliaries) such as:

Automatic Voltage Regulators,

Remedial Action Schemes (RAS) and

System loading (monitored by state estimator, RTCA, SCADA Alarming and transmission displays).

CAISO RC members are required to report to CAISO RC any status changes to RAS or when Automatic Voltage Regulators are not in service.

5.10.2. Current pre-Contingency element conditions (voltage, thermal, or stability) – are monitored by state estimator, SCADA Alarming, RTCA transmission and summary displays.

5.10.3. Current post-Contingency element conditions (voltage, thermal, or stability) – are monitored by RTCA, VSA, DSA and transmission displays.

5.11. CAISO RC monitors the availability and deployment of reactive reserves, by monitoring post-Contingent steady state voltages. Reactive Reserve inquiries are made as needed with applicable parties when reactive reserves in real-time appear inadequate or lower than expected.

5.12. Capacity and energy conditions for all CAISO RC participants are determined in Day Ahead (DA) and monitored in real-time, in accordance with CAISO RC Reliability Processes.

5.13. The CAISO RC monitors current BA ACEs and System Frequency trends. This information is used to ensure that a participating BA’s failure to adhere to NERC BAAL Control Standards is not contributing to reliability-related issues. This includes IROL/SOL exceedances or capacity-related issues. If failure to conform to BAAL standards is


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contributing to an IROL exceedance, the CAISO RC will order the use of all resources, including firm load shedding, to relieve the exceedance.

5.14. Planned transmission or generation outages are reported to CAISO RC via the Outage Management System (OMS) or other outage reporting applications as agreed to with participants. This outage information, once approved and implemented, automatically or manually updates the Full Network model.

5.15. State estimator, RTCA, SCADA Alarming, and transmission displays monitor Contingency Events. Member control centers report Contingency Events on non-monitored facilities, if needed, to CAISO RC.

5.16. CAISO RC monitors BES parameters that may have significant impacts upon its Reliability Coordination Area and neighboring Reliability Coordination areas with respect to:

5.16.1. CAISO RC monitors all BES facilities within its RC area for current and projected loadings. If reliability impacts are expected or are occurring, the CAISO RC may utilize all available resources, up to and including load shedding, to address a potential or actual IROL exceedance. The CAISO RC has EMS displays, which allow RC operators to watch and monitor all IROL limits.

5.16.2. CAISO RC monitors participating BA’s and Reserve Sharing Groups’ (RSG) Contingency Reserve Actual (CRA) versus their Contingency Reserve Obligation (CRO) to ensure the necessary amounts of Operating Reserves are available as required to meet NERC BAL and EOP Standards. If needed, the CAISO RC will undertake Energy Emergency Alert (EEA) procedures or assist with obtaining additional reserves from neighbors.

5.16.3. CAISO RC identifies the cause of potential or actual SOL or IROL exceedance via analysis of state estimator results, RTCA results, VSA results, DSA results, SCADA Alarming of outages, transmission displays of changes, and Interchange Transaction impacts. CAISO RC will direct or instruct actions including transmission reconfiguration, generation re-dispatch, or emergency procedures to relieve the potential or actual IROL exceedance without delay, and in no longer than 30 minutes. CAISO RC is authorized to direct utilization of all resources, including load shedding, to address a potential or actual IROL exceedance.

5.17. CAISO RC communicates Geo-Magnetic Disturbance forecast information to participating BAs and TOPs via the CAISO RC Messaging tool. CAISO RC will assist in development of any required response plan and may move to conservative operating mode to mitigate impacts as needed.

5.18. CAISO RC initiates NERC Hotline discussions, to assist in the assessment of reliability of the Regions and the overall interconnected system, and coordinates actions in anticipated or actual emergency situations. CAISO RC will disseminate this information via the CAISO RC Messaging tool or by individual phone calls.

5.19. CAISO RC coordinates, on an as-needed basis, with other Reliability Coordinators and member BAs and TOPs on the development and implementation of action plans to mitigate potential or actual SOL, IROL, BAAL or DCS/BCE exceedance.

5.20. The participating BAs and TOPs within the CAISO RC Reliability Area inform CAISO RC of all changes in status of RAS, including any degradation or potential failure to operate as


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expected. CAISO RC factors these RAS changes into its reliability analyses and updates its Contingency definitions as appropriate.

5.21. CAISO RC confirms reliability assessment conclusions by analyzing results of state estimator/RTCA and discussions with participating BAs and TOPs and neighboring Reliability Coordinators. CAISO identifies options to mitigate potential or actual SOL or IROL exceedance by examining existing operating procedures, system knowledge, and power flow analysis to identify and implement only those actions necessary to act in the best interests of the interconnection.

6. Emergency Operations

6.1. CAISO RC applies operating procedures, RC0310 - Mitigating SOL and IROL Exceedances and RC00410 - System Emergencies (See appendix D), to direct or instruct its TOPs to return the transmission system to within SOL or IROL limits as soon as possible, but no longer than within 30 minutes, to prevent a single or credible multiple Contingency from resulting in instability, uncontrolled separation, or Cascading Outages that adversely impact the reliability of the BES. These actions may include: reconfiguration, re-dispatch, load transfer, schedule curtailment, controllable device operation or load shedding. Load shedding will be considered a last resort to mitigate reliability issues that occur in real-time.

6.2. CAISO RC will use RC0310 - Mitigating SOL and IROL Exceedances and/or RC0410 - System Emergencies (See appendix D) when it determines that IROL exceedances are imminent. CAISO RC procedures document the processes that CAISO RC follows when directing or instructing BAs and TOPs in the actions to be taken to mitigate the IROL exceedance to return the system to a reliable state. CAISO RC coordinates its emergency procedures with other Reliability Coordinators, per Appendix B.

6.3. CAISO RC directs or instructs BAs and TOPs to take actions in the event the loading of transmission facilities progresses to, or is projected to progress to, a SOL or IROL exceedance. Corrective actions may include: reconfiguration, re-dispatch and/or load shedding to prevent or relieve SOL or IROL exceedance. CAISO RC will not rely on, nor wait for, the Qualified Transfer Path Unscheduled Flow (USF) procedure to relieve IROL exceedance. CAISO RC will assist with coordination of the USF procedure, if doing so will provide additional relief. CAISO RC will adhere to the USF procedure instructions, including curtailing transactions.

6.4. CAISO RC utilizes RC0410 - System Emergencies (See appendix D) to mitigate an Energy Emergency within its Reliability Coordination Area. CAISO will provide assistance to other Reliability Coordinators, per its respective joint operating agreement listed in Appendix B.

6.5. CAISO RC utilizes RC0410 - System Emergencies (See appendix D) when it, or a BA or TOP within its Reliability Coordination Area is experiencing a potential or actual Energy Emergency. CAISO Emergency Operations document the processes and procedures that CAISO uses to mitigate the emergency condition, including a request for emergency assistance if required.

6.6. CAISO RC will coordinate drills and simulations on a regular basis to reinforce competencies required for implementation of Emergency procedures.


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7. System Restoration

7.1. Knowledge of CAISO RC Area TOP Restoration Plans – CAISO RC is aware of each TOP’s System Restoration Plan and has a written copy of each plan. During system restoration, CAISO RC monitors restoration progress and acts to coordinate any needed assistance. CAISO RC will coordinate the restoration activities, depending on system conditions.

7.2. System Restoration Plan – The CAISO RC Restoration protocols are contained in the RC System Restoration Plan. Following a Disturbance in which one or more areas within the CAISO RC Area become isolated or blacked out, the CAISO RC System Operators will implement the CAISO RC Restoration Plan. The scope of the CAISO RC’s Restoration Plan ends when all of the TOPs in the CAISO RC Area are interconnected, each TOP has transferred authority back to its respective BA(s), the CAISO RC Area is interconnected to its neighboring RC Areas and normal operations can be resumed. This Restoration Plan is drilled at least annually or more frequently, as needed.

7.3. Dissemination of Information - CAISO RC serves as the primary contact for disseminating information regarding Restoration to neighboring Reliability Coordinators and members not immediately involved in Restoration.

7.4. Restoration - CAISO RC approves, communicates and coordinates the re-synchronizing of major system islands or synchronizing points so as not to cause a burden on member or adjacent Reliability Coordination Areas.

8. Coordination Agreements and Data Sharing

8.1. Coordination Agreements: See Appendix B

8.2. Data Sharing - CAISO RC determines the data requirements to support its Reliability Coordination tasks and requests such data from members or adjacent Reliability Coordinators. CAISO provides for data exchange with participating BAs and TOPs and adjacent Reliability Coordinators via a secure network. CAISO RC members provide data to CAISO RC via mutually agreeable transfer methods identified in the CAISO RC’s IRO-010 Data Specification. CAISO RC provides data to entities outside CAISO via direct links and mutually agreeable transfer methods identified in IRO-010 Data Specifications.

9. Facility

9.1. Business Continuity-CAISO RC performs the Reliability Coordinator function at the California ISO Headquarters in Folsom, CA, along with the CAISO control center in Lincoln, CA. The Folsom and Lincoln control centers have the necessary voice and data communication links to appropriate entities within CAISO RC Reliability Area to perform their responsibilities. These facilities are staffed 24x7, and are available to act in addressing a real-time emergency condition.

9.2. Adequate Communication Links - CAISO RC maintains satellite phones, cellular phones, and redundant, diversely-routed telecommunications circuits. There is also a video link between the Folsom and Lincoln Control Rooms.


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9.3. Multi-directional Capabilities – CAISO RC has multi-directional communications capabilities with its members and neighboring Reliability Coordinators, to meet reliability needs of the Interconnection, for both voice and data exchange.

9.4. Real-time Monitoring – CAISO RC has detailed capability for real-time monitoring of its Reliability Coordination Area and Reliability Coordinators adjacent to the CAISO Reliability Coordination Area, to ensure that potential or actual SOL or IROL exceedance is identified. CAISO RC monitors BES elements (generators, transmission lines, buses, transformers, breakers, etc.) that could result in SOL or IROL exceedance within its Reliability Coordination Area. CAISO RC monitors both real and reactive power system flows, operating reserves, and the status of the Bulk Power System elements that are, or could be, critical to SOLs and IROLs and system restoration requirements within its Reliability Coordination Area.

9.5. Study and Analysis Tools - CAISO RC has adequate analysis tools, including state estimation, pre-and post-Contingency analysis capabilities (thermal, stability, and voltage), and wide-area overview displays. CAISO RC has detailed monitoring capability of the CAISO Reliability Area and sufficient monitoring capability of the surrounding Reliability Areas to ensure potential reliability issues are identified. CAISO RC continuously monitors key transmission facilities in its area in conjunction with the Members’ monitoring of local facilities and issues.

The systems CAISO RC uses include:

Energy Management System (EMS)/Supervisory Control and Data Acquisition (SCADA) System:

o EMS provides the RC operator with real-time monitoring and visibility of the status of BES transmission and generation facilities, RASs, non-BES facilities that impact the BES, and other critical real-time parameters for the reliable operation of the BES. The EMS system also provides alarming of critical events that affect the reliability of the BES.

State Estimator (SE):

o This is an application that performs numerical analysis of the real-time network model and data to determine the system’s current condition. The SE can typically identify bad analog telemetry, estimate non-telemetered flows and voltages and determine real time operating limit exceedances. The SE runs every 5 minutes, and provides a base-case solution used by RTCA and VSA applications.

Real-time Contingency Analysis (RTCA):

o This is a primary Real-time Assessment application that runs every 5 minutes and automatically performs analyses of all identified single and credible multiple Contingencies that affect the RC Area. The RC operator uses the results to identify potential post-Contingency thermal or voltage exceedances on the system and to proactively develop mitigation plans to ensure reliability.

Real-time Voltage-Stability Analysis (VSA):

o This application runs every 5 minutes and performs voltage-stability analyses of predetermined stability limitations on the system to determine voltage-stability limits and margins for those interfaces.


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Real-time Dynamic Stability Analysis (RT-DSA):

o This application runs every 15 minutes and performs transient stability analyses of predetermined stability limitations on the system to identify transient-stability limits and margins for those interfaces.

Plant Information (PI) System:

o This is a reliability tool used to process and provide visualization of complex real-time power system information in a user-friendly format for the RC operator to process and analyze. The tool provides real-time trending of power system parameters, which enhances situational awareness.

Dispatcher Load Flow (DLF) and Contingency Analysis (CA) Study Tools:

o These applications are used by the RC operator to manually run load flow and Contingency analysis studies. The Real-time base case solution from SE can be loaded into these applications, to be used as a starting point to run offline analysis of any scenario the operator wants to study.

9.5.1. CAISO RC maintains control standards for its monitoring and analysis tools, including approvals for planned maintenance. CAISO has procedures in place to mitigate the effects of analysis tool outages. CAISO RC ensures that SOL and IROL monitoring continues, even if the main monitoring system is unavailable. CAISO has backup facilities that shall be used if the main monitoring system is unavailable.

10. Staffing

10.1. Staff Adequately Trained and NERC Reliability Coordinator Certified Personnel – The 24 x 7 CAISO RC team consists of:

Lead Reliability Coordinator,

Reliability Coordinators, and

Operations Engineers.

All personnel in these positions possess the NERC Reliability Coordinator certification.

10.2. Compliance - CAISO RC has continuous access to staff who are directly responsible for complying with NERC and WECC Standards.

10.3. Comprehensive Understanding - CAISO RC operating personnel have an extensive understanding of the BES system within the CAISO RC Area, operating practices, operating procedures, operating guides, restoration priorities, restoration objectives, outage plans, equipment capabilities and operational restrictions.

10.4. Priority - CAISO RC operating personnel place particular attention on SOLs and IROLs and intertie facility limits. CAISO RC ensures that protocols are in place allowing CAISO RC operating personnel to have the best available information at all times.

10.5. Continuous Training - CAISO’s RCs are continuously trained on an ongoing basis to perform their duties, and CAISO Operational Readiness Group uses the “Vision Learning Station”


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application and NERC System Operator Certification and Continuing Education Database (SOCCED) to track the status of each Reliability Coordinator’s training progress, certification and desk qualifications. CAISO RCs are expected to regularly participate and take an active role in regional reliability training.

11. APPENDIX A – California ISO Governing Documents

11.1. California ISO Operating Agreement - California ISO Website link: http://www.caiso.com

11.2. California ISO Transmission Tariff California ISO Website link: California ISO Website link: http://www.caiso.com

12. APPENDIX B – Agreements with External Entities

12.1. Peak Reliability

13. APPENDIX C - California ISO Reliability Area Map

13.1 CAISO RC Reliability Map for July 1, 2019


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13.2 List of Participating Balancing Authorities and Transmission Operators for July 1, 2019.

Entity BA TOP

Arizona Electric Power Cooperative, Inc. (AEPCO) X

Balancing Authority of Northern California (BANC) X

CENACE* X X

City and County of San Francisco (HHWP) X

City of Santa Clara - Silicon Valley Power (SNCL) X

Imperial Irrigation District (IID) X X

Los Angeles Department of Water and Power (LADWP) X X

Modesto Irrigation District (MID) X

Pacific Gas and Electric Company (PGAE) X

Sacramento Municipal Utility District (SMUD) X

San Diego Gas & Electric Company (SDGE) X

Southern California Edison (SCE) X

Trans Bay Cable LLC X

Turlock Irrigation District (TID) X X

Valley Electric Association, Inc. X

Western Area Power Administration - Sierra Nevada Region (WASN)

X

*Not a NERC registered entity


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14. APPENDIX D – California ISO Reliability Coordination Procedures

Procedure Number Procedure Title

RC0100 Reliability Coordinator Authority

RC0110 Communications Protocols

RC0120 Guidelines for IRO-010 Data Specification

RC0120A IRO-010 Data Specification

RC0130 Notification Requirements for Real-Time Events

RC0210 Monitoring Frequency and Balancing Authority Performance

RC0220 Time Error Correction

RC0310 Mitigating SOL and IROL Exceedances

RC0320 Outage Review and Coordination

RC0330 Coordination with Neighboring RCs

RC0410 System Emergencies

RC0420 Event Reporting

RC0430 GMD Operating Plan

RC0460 Reliability Coordinator Area Restoration Plan

RC0460A Restoration Principles

RC0460B Whole_Partial System Restoration Checklist

RC0460C Blackout Restoration Using Connection to Energized System Checklist

RC0460D Blackout Restoration Energizing a De-energized System Checklist

RC0460E Synchronization Checklist

RC0460F EOP-005 Plan Review Checklist

RC0470 Loss of Control Center Functionality

RC0510 Quality Assurance of Monitoring and Analysis Tools

RC0520 Loss of Monitoring and Analysis Tools

RC0530 Communications Systems and Testing

RC0540 WIT Administration/ Inadvertent Payback Process

RC0550 RC Procedure Exchange and Distribution Process

RC0560 IROL Dissemination

RC0610 System Operating Limits Methodology For The Operations Horizon


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Procedure Number Procedure Title

RC0620 Operations Planning Analysis (Next Day)

RC0630 Outage Coordination Process

RC0640 Planning Assessment Provision Process (IRO-017 R3, R4)

RC0650 System Behavior Data Provision (MOD-033)

RC0660 Transmission Relay Loadability (PRC-023)

RC0670 Disturbance Monitoring and Reporting Requirements Process (PRC-002)

RC9000 Open Loop Guideline

RC9100 Nuclear Plant Interface Coordination

RC9510 Victorville-Lugo IROL Operating Guide

RC9520 San Diego-Cenace Import IROL Operating Guide

RC9220 Oregon Export IROL Operating Guide

Version History

Version Change Date

Final Draft Updated with final changes, minor grammar/formatting changes

10/24/18

Final Appendix updated 1/14/2019

Final Endorsed by NERC Operating Reliability Subcommittee 2/12/2019

Agenda Item 6b OC Meeting

March 5-6, 2019


Group: Resources Subcommittee Purpose: Status Update Last Meeting: January 23-25, 2019 Location: Austin, TX Duration: 2.5 Days Next Meeting: April 23-25, 2019 Location: Valley Forge, PA Duration: 2.5 Days Chair: Tom Pruitt, Duke Energy Vice-Chair: Sandip Sharma, ERCOT

2019 Initiatives: We continue to focus on regular review, update, and communication of Guidance Documents and Reference Guides within our area of responsibility. We also continue to prepare for implementation of the IDC PFV, following the ongoing field trial. Throughout 2019, we will be monitoring RC developments in the Western Interconnection and will collaborate with other sub-groups to examine improvements in short and mid-term forecasting. Items for OC Approval:

NERC Primary Frequency Response Guideline Document – The final draft of the revised document was reviewed and authorized to be posted for comment by the OC at the December meeting. The 45 day comment period will end on February 18. The RS sub-team plans to address the comments and revise the document accordingly. The responses to comments and the revised document will be provided to the OC as soon as it available.

NERC Balancing Authority Area Footprint Change Tasks Reference Document (initial version) – The final draft of the revised document was reviewed and authorized to be posted for comment by the OC at the December meeting. The 45 day comment period will end on February 18. The RS sub-team plans to address the comments and revise the document accordingly. The responses to comments and the revised document will be provided to the OC as soon as it available.

Key Issues for OC Information:

July 10 Eastern Interconnection Frequency Event – Results of the voluntary AIE survey of the same 12 largest BAs were reviewed (primarily to review NIA/NIS by individual interface). Similar to the previous review of one minute data, no definite conclusions could be drawn. These results were reported to the OC at the December meeting and further collection and analysis of hourly and one minute data was not recommended. At

the January RS meeting, the results were discussed further and an RS sub-team will review all information gathered to date further to draw any other conclusions.

January 11 Eastern Interconnection Frequency Oscillation – A report on the progress of the SMS-led investigation were covered by Ryan Quint at the RS meeting. Investigation continues and the RS will provide assistance as needed.

Reliability Guideline: Integrating Reporting ACE with the NERC Reliability Standards – A sub-team was established to review and revise this document. A draft for posting will be brought to the OC at the December meeting. Related to this effort, a SAR to revise the Reporting ACE definition in the NERC Glossary is currently being considered.

Time Monitoring Reference Document and Dynamic Transfer Reference Document – Members were identified to support the ORS in the review and revision of these documents.

RS Review of BAL-002 SAR – The Resources Subcommittee opinion on the soundness of the request is that the SAR should not go forward as written. The recommended modification of R1.1 of this standard to include interconnection frequency assessment will modify the original intent of standard, which is the demonstration of the deployment of reserves to recover from Reportable Balancing Contingency Events (RBCEs).

However, the concerns raised in this SAR can be addressed by other means.

Dissenting Opinion on BAL-002: “The SAR request has technical merit based on the fact that it is contrary to reliability for the rules to incent resources to continue to inject power into the interconnection when the frequency is already high and rising. There are many complicating issues and many potential solutions that should be presented to the industry for discussion—this is what the SAR process does.”.

RS Frequency Working Group (FWG) – The FWG selected M4 and BAL-003-1 frequency events for September 2018, October 2018, and November 2018 for the interconnections prior to the January RS meeting. The final Operating Year 2018 list of events were reviewed at the RS meeting and the approved list was posted on the NERC website on February 1.

RS Inadvertent Interchange Working Group (IIWG) – An update on the interconnection inadvertent interchange was provided and balances continue to trend downward. The Eastern Interconnection trend beginning near the end of 2017 continues, but the 50% drop in the rate in August continues. The cause(s) continues to be investigated, and one possible contributor, unilateral inadvertent payback, is being investigated.

Reserves Working Group (RWG) — Chair Tony Nguyen reviewed the voluntary DCS submittal process for BAL-002-2. Additional changes to the form to accommodate BA footprint changes were reviewed and implemented.

Generator Survey – The plan forward was discussed and the sub-team will begin identifying events for each interconnection for the next iteration of surveys.

Changes in BA Area Footprints – In the EI, integration of OVEC into PJM Balancing Area RC occurred on December 1, 2018. In the WI, AVRN will pseudo tie with another BA (causing a need to reallocate FRO in Q3), NWPP will add 2 members to the RSG, and a new gen-only BA planned; exact dates for each of these changes are to be determined.

Quarterly Reviews

BA Performance Data – CPS1 and BAAL data submitted for the 4th quarter of 2018 was reviewed.

Time Error – Time error reports for 4th quarter of 2018 were reviewed.

ERS Measures – Measures 1, 2, 4, and 6 were reviewed. A sub-team continues to review additional refinements in analysis and possible additional sub-measures.

Interconnection Frequency Performance - performance for all the interconnections was reviewed. Other than the events noted above, no significant issues were noted.

Agenda Item 6c OC Meeting

March 5-6, 2019


Group: Event Analysis Subcommittee (EAS) Purpose: The EAS is a cross-functional group of industry experts that will support and maintain

a cohesive and coordinated event analysis (EA) process across North America with industry stakeholders. The EAS will support development of lessons learned, promote industry-wide sharing of event causal factors and assist NERC in implementation of related initiatives to lessen reliability risks to the Bulk Electric System.

Last Meeting: December 10, 2018 Location: Atlanta, GA Duration: ½ Day Next Meeting: March 4, 2019 Location: Pittsburgh, PA Duration: ½ Day Conference Calls: 2nd and 4th Monday of every month from 11:00 a.m. – Noon ET Chair: Rich Hydzik, Avista Corp Vice-Chair: Vinit Gupta, ITC Holdings

Items for OC Approval:

Data Exchange Infrastructure Requirements Task Force (DERTF) requests OC approval to post the Draft Data Exchange Infrastructure Requirements Compliance Implementation Guidance document for 45-day comment period.

Key Issues for OC Resolution:

None

Key Issues for OC Information:

EAS Lesson Learned presentation on Substation Fires and First Responders.

The EAS Reliability Review Taskforce conducted a webinar on February 27, 2019 to cover updates to the Reliability Guideline: Generating Unit Operations During Complete Loss of Communications. The webinar presentation and streaming video will be posted to the NERC website.

Lessons learned summary of additions since last OC meeting.

The 2019 Monitoring and Situational Awareness Technical Conference is scheduled for September 24-25, 2019 at Southwest Power Pool in Little Rock, AR. An announcement will be sent out to industry in the second quarter. with the conference registration links and travel information, this information is also available on the NERC calendar.

The 2019 Cold Weather Preparation Webinar has been scheduled for Thursday, September 5, 2019 from 2:00-3:00 p.m. ET. An announcement will be sent out to

industry in August with the webinar registration link, this information is also available on the NERC calendar.


EAS is conducting outreach to drive lessons learned submittals through not only the ERO EA Process but through other occurrences or near occurrences experienced by entities.

Future Initiatives/ Deliverables:

Review Event Analysis Process document as required

Recommend need for training in coordination with Personnel Subcommittee (PS)

Publish lessons learned as required

Develop Reliability Guidelines

Identify significant risk and the need for NERC Alerts

Updates to the OC

Input to the NERC Performance Analysis Subcommittee’s (PAS) annual State of Reliability Report

Information and recommendations related to the Event Analysis process

External requests to group:

Outreach and coordination with NATF/NAGF regarding lesson learned usability

The NAGF is actively participating in the EAS

Outreach and coordination with other NERC groups (PS, PAS, RS, ORS, and PC). Liaisons established with PS and PAS

Leadership calls are set up prior to OC meetings

Coordinating with PAS on 2018 State of Reliability Report

Internal requests to group:

None at this time

Group’s recurring deliverables:

EAS continues to manage the ERO Event Analysis Process Document update process as required

Action oriented Lessons Learned posted on NERC website

EAS will continue to review and address reliability issues that pose a risk to the BPS and share information with the OC and industry

Any NERC Programs Oversight Responsibility for the Group:

No

Any NERC Document (non-Reliability Standard) Responsibility for the Group:

ERO Event Analysis Process Document

Agenda Item 6d OC Meeting

March 5-6, 2019


Group: Personnel Subcommittee (PS) Purpose: The PS’s goal is to support the development of continuing education (CE) program

requirements that promote excellence in training programs and advance improved performance of bulk power system personnel.

Last Meeting: February 5-6, 2019 Location: Manhattan Beach, CA Next Meeting: May 14-15, 2019 Location: Atlanta, GA Chair: Rocky Williamson Vice-Chair: Leslie Sink

Items for OC Approval:

None Key Issues for OC Resolution:

None Key Issues for OC Information:

The February meeting included a joint meeting with the Personnel Certification Governance Committee (PCGC). The meeting was an opportunity for the PS and PCGC to present program achievements and discuss the CE program as the credential maintenance tool for the NERC System Operator Certification program.


The PS is working on a comprehensive evaluation of adult learning principles and instructional design concepts in order to develop program criteria that results in quality learning events.

Industry Outreach

Outreach and coordination with other NERC groups (i.e. EAS) Recurring Deliverables of Group

The review and approval of CE courses.

The review and approval of NERC Approved CE providers.

Audits of CE courses and providers.

The PS completed 51 provider audits in 2018.

There were 20 provider audits completed in Q1 2019.

The PS will reinstate level 2 course audits in Q2. NERC Program’s Oversight Responsibility for the Group

Industry oversight of the NERC CE Program NERC Document (Non-Reliability Standard) Responsibility for the Group

Quarterly CE Program Report to PCGC and OC

CE Program Administrative Manual

CE Program Trainer/training guidelines Continuing Education Program Statistics The CE program has 192 active providers. For 2018, a total of 2,397 courses were approved which entailed 10,261.75 CE hours. PS Work Plan 2019-2021


CE Program Manual 5.0 (Major Revision/Rewrite) TBD

Construct guidelines In progress Q1 - 2019

Revise audit requirements In progress Q1 - 2019

Revise administrative requirements In progress Q2 - 2019

Review and approval process (Tech Pub and OC) Q2 - 2019 Q3 - 2019

Edit and finalize Q3 - 2019 Q1 - 2019

Implement Change Management Plan Q4 - 2019 Q1 - 2020

Release CE Program Manual 5.0 Q1 - 2020 Q1 - 2020

Monitor and assess CE Program Manual 5.0

Industry survey Q2 - 2020 Q3 - 2020

Evaluate Q3 - 2020 Q4 - 2020

Define scope (5.1) Q4 - 2020 Q1 – 2021

Situational Awareness for the System Operator In progress Q1 – 2020

Review and Update PS Scope document In progress Q3 – 2019

Conduct Level 2 course audits and provider audits In progress on-going

Reliability Assessment

SubcommitteeStatus Report

Tim Fryfogle, RAS Chair

Operating Committee Meeting

March 5-6, 2019


Summary

• 2019 Summer Reliability Assessment

• 2019 Long Term Reliability Assessment

• Probabilistic Assessment Working Group

• RAS Schedule

Outline


2019 Summer Reliability Assessment

Date Milestone

January 25 Sub team review and discussion of SRA inputs and operational risk scenario

Feb 5-6 RAS Meeting: Review data request, discuss seasonal reliability methods

February 12 Data and Narrative Request sent to Regional Executives and RAS

April 5 Data and Narrative responses due to NERC

April 8-18 Report Development-Dashboards sent out ASAP

April 18 Released to RAS

April 23-24 RAS Meeting: Review data request, discuss initial findings

April 22-26 RAS Review Period

April 26 All comments from RAS due - NERC incorporates all comments

May 1 Draft sent to PC for Review

May 1-10 PC review period- NERC incorporates all comments

May 13 Updated Report sent to PC for vote

May 14 Webinar to review changes Possible move to middle of voting period

May 14-18 PC electronic voting period

May 13-17 Publications Review Report

May 21 Report sent to Executive Management for approval

May 30 Report Release


2019 Summer Reliability Assessment

Expected Operating Reserve Requirement at Peak

Reference Margin Level

Demand Scenarios

Resource Scenario

Example Seasonal Risk Scenario


2019 Long-Term Reliability Assessment

Date MilestoneFebruary 13 NERC Posts 2019 LTRA Materials to NERC RAS Webpage and sends Request Letter to Regional ExecutivesFebruary 13– June 21 Regional Entities/Assessment Areas Collect Data and Develop NarrativesMay 1 – June 21 Individual Assessment Webinars: Upon request, NERC and Individual Assessment Areas / Regions Discuss and Address

Data / Narrative Issues

June 21 Regional Entities/Assessment Areas submit Preliminary Data Sheet and Preliminary Narrative to NERC on RASSharepoint

June 26 Peer Review Comment Period Begins: NERC Staff posts Preliminary Narratives and Peer Review Comment Matrix on RAS Sharepoint

July 5 Peer reviewers post completed Peer Review Comment Matrix on RAS SharePoint July 9-11 RAS Face to Face Meeting: Assessment Area Presentations, Review of Narratives, Discuss Initial Responses to Feedback

July 19 Regional Entities/Assessment Areas post completed Peer Review Comment Matrix on RAS SharepointJuly 26 Regional Entities/Assessment Areas post the Final Narratives, Area Summaries and Final Datasheet on RAS Sharepoint

August 27-28 RAS Face to Face Meeting: Review Front SectionSeptember 3-6 NERC Staff update front section and Dashboards according to RAS Feedback September 6 NERC Staff provides RAS rough draft of report and initial key findings for OC/PCSeptember 10 – 11 PC Webinar: NERC Staff Present Initial LTRA Key Findings to OC/PCSeptember 13 RAS Webinar: Review LTRA Draft (page turn) and RAS to provide Informal Feedback on Key FindingsSeptember 17 NERC to send Draft LTRA Report to PC and RASSeptember 17 – 27 PC Review of Draft LTRA Report September 27 PC provides feedback to NERC by COB on September 27September 30- October 4 NERC Staff Reviews PC FeedbackOctober 7 NERC Staff Sends Updated Report with Comment Matrix to the PCOctober 14 PC Webinar: NERC Staff Hosts Webinar with PC on Updated Report; Discuss Any Remaining FeedbackOctober 14 – 18 PC Electronic Vote for Report AcceptanceOctober 21 – November 8 NERC Technical Publications and NERC Executive Management reviewNovember 11 – 22 NERC Board of Trustees Review of LTRAFirst week of December NERC Board of Trustees Approval of LTRADecember 9 Target Release


• Data Collection Approaches and Recommendations Report High priority in 2019

• Engagement Provide forum for discussion of probabilistic studies across industry

groups.

o Host 1-2 Forums on Probabilistic Studies

o High Priority in 2019

• Expand Upon Margin Scenario and Discussion on non-peak hour risk Whitepaper

Moderate

PAWG Work Plan


• April 23-24 Boston, MA SRA Review

Approve WRA schedule

• July 9-11 Portland, OR LTRA Peer Review

Assessment Area presentations

• August 27-28 Pittsburg, PA Review LTRA

WRA kickoff

Schedule


Parallel Flow Visualization (PFV)

Dave Devereaux, Senior Manager, IESO

March 5, 2019

• Review the current Interchange Distribution Calculator (IDC)

• Describe the changes coming with the new IDC, Parallel Flow Visualization (PFV)

• Discuss next steps for the PFV project

Today’s Agenda

2

• Real-time congestion management tool used to calculate impacts of transactions/generation on flowgates throughout the interconnection

• IDC has basic data inputs therefore the results are created based on certain assumptions

• The industry has been working towards a new IDC (PFV) with enhanced inputs and more accurate impact calculations

Current IDC

3

• PFV will use real-time telemetry to calculate transaction/GTL (generation-to-load) impacts

• Every Reliability Coordinator submits real-time data every 15mins which includes:

– Generator Outputs

– Interface flows

– Phase shifter information

– Outage information

– Load forecast

Parallel Flow Visualization (PFV)

4

Inputs into IDC vs PFV

5

Input Current IDC PFV

Transactions

Load Forecast

Outages

Phase Shifter Information

Generator Outputs

Tie-line Flows

Interface Flows

DC tie information

Dynamic Schedules

• PFV will areas to assign different priority levels for generation (same methodology as tags)

• Credit for re-dispatch was created to ensure balancing authorities receive a credit when GTL relief is provided

• Exceedance/Shortfall rules were created to help relieve/penalize areas that do not provide their required GTL relief

• All the above rules align with NAESB standards

Enhanced Generation to Load curtailment

6

• PFV has been running in parallel with IDC for ~18 months (since Sept 2017)

• All real-time TLR’s issued in the IDC are being mimicked in PFV

• Results are being analyzed to ensure the accuracy of PFV results

PFV Parallel Run

7

• Interchange Distribution Calculator Working Group (IDCWG) continue to review the performance of PFV

• IDCWG will provide the IDCSC a recommendation on whether to move forward with PFV in the next several months.

• ORS will review and recommend to OC for final approval

Next Steps

8

Questions?

9

Agenda Item 15 OC Meeting

March 5-6, 2019 Project 2017-01 Modifications to BAL-003-1.1 Frequency Response and Frequency

Bias Setting Action

For informational purposes and in connection with proposed Reliability Standard BAL-003-2, the Project 2017-01 standards drafting team is presenting the NERC Operating Committee (OC) the attached changes to the Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard document. Background

The supporting documents for BAL-003-1 were developed using engineering judgment on the data collection and process needed to determine the Interconnection Frequency Response Obligation (IFRO), as well as the processing of raw data to determine compliance. Since Reliability Standard BAL-003-1.1 has been implemented and the data became available for analysis, minor errors in assumptions and process inefficiencies have been identified. It was anticipated that as frequency response improves, the approaches embedded in the standard for annual samples needed to be modified. The BAL-003-2 Phase I portion of the project revises the BAL-003-1.1 standard and process documents to address: (1) the inconsistencies in calculation of IFROs due to Interconnection Frequency Response performance changes of Point C and/or Value B; (2) the Eastern Interconnection Resource Contingency Protection Criteria; (3) the frequency of nadir point limitations (currently limited to t0 to t+12); (4) clarification of language in Attachment A, i.e. related to Frequency Response Reserve Sharing Groups (FRSG) and the timeline for Frequency Response and Frequency Bias Setting activities; and (5) the BAL-003-1.1 FRS Forms enhancements that include the ability to collect and submit FRSG performance data. In addition to fixing the inconsistencies identified in the Frequency Response Annual Analysis Report1, supporting procedural and process steps have been removed from Attachment A and reassigned to the Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard, an ERO-approved Reference Document, such that timely process improvements can be made as future lessons are learned. The attached document reflects those changes. Project 2017-01, Phase I, was posted for a 45-day formal comment period from December 4, 2018 - January 17, 2019, including the Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard posted as a supporting document to the project. The Project 2017-01 standards drafting team considered all industry comments received from the September 2018 informal comment period in the development of BAL-003-2.

1 See e.g., FRAA Report, at p. v, available at, http://www.nerc.com/comm/OC/Documents/2016_FRAA_Report_2016-09-30.pdf (discussing IFRO calculations).

http://www.nerc.com/comm/OC/Documents/2016_FRAA_Report_2016-09-30.pdf

NERC | Report Title | Report Date I

Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard

Version II

NERC | Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard – Version II | 2019 ii

Table of Contents

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

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

Chapter 1 : Event Selection Process ................................................................................................................................ 1

Event Selection Objectives .......................................................................................................................................... 1

Event Selection Criteria ............................................................................................................................................... 1

Quarterly .................................................................................................................................................................. 2

Annually ................................................................................................................................................................... 3

Chapter 2 : Process for Adjusting Interconnection Minimum Frequency Bias Setting ................................................... 4

Chapter 3 : Interconnection Frequency Response Obligation Methodology ................................................................. 5

Interconnection RLPC Values ...................................................................................................................................... 6

Chapter 4 : Version History ............................................................................................................................................. 8

NERC | Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard – Version II | 2019 iii

Preface

The vision for the Electric Reliability Organization (ERO) Enterprise, which is comprised of the North American Electric Reliability Corporation (NERC) and the seven Regional Entities (REs), is a highly reliable and secure North American bulk power system (BPS). Our mission is to assure the effective and efficient reduction of risks to the reliability and security of the grid. The North American BPS is divided into seven RE boundaries as shown in the map and corresponding table below. The multicolored area denotes overlap as some load-serving entities participate in one Region while associated Transmission Owners/Operators participate in another.

FRCC Florida Reliability Coordinating Council

MRO Midwest Reliability Organization

NPCC Northeast Power Coordinating Council

RF ReliabilityFirst

SERC SERC Reliability Corporation

Texas RE Texas Reliability Entity

WECC WECC

NERC | Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard – Version II | 2019 iv

Introduction

This procedure outlines the ERO process for supporting the Frequency Response Standard (FRS). A request for revisions may be submitted to the Operating Committee (OC) for consideration. The request must provide a technical justification for the suggested modification. The ERO shall publicly post the suggested modification for a 45-day formal comment period and discuss the request in a public meeting of the OC. The ERO will make a recommendation to the NERC Board of Trustees (Board), which may adopt the revision request, reject it, or adopt it with modifications. Any approved revision to this Procedure shall be filed with the Federal Energy Regulatory Commission (FERC) for informational purposes. BAL-003-2 sets Interconnection Frequency Response Obligation (IFRO) to preset values subject to annual review. This procedure establishes the methods to be used for the annual review until Phase 2 of the SAR for Project 2017-01 has been addressed. If Frequency Response Measure (FRM) for the Eastern Interconnection degrades more than 10 percent in a year, the ERO will halt the reduction in IFRO until such time as a determination can be made as to the cause of the degradation.

NERC | Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard – Version II | 2019 1

Chapter 1: Event Selection Process

Event Selection Objectives The goals of this procedure are to outline a transparent, repeatable process to annually identify a list of frequency events to be used to calculate Frequency Response to determine:

Whether the Balancing Authority (BA) or Frequency Response Sharing Group (FRSG) met its Frequency Response Obligation, and

An appropriate fixed Frequency Bias Setting.

Event Selection Criteria

1. The ERO will use the following criteria to select FRS excursion events for analysis. The events that best fit the criteria will be used to support the FRS. The evaluation period for performing the annual Frequency Bias Setting and the FRM calculation is December 1 of the prior year through November 30 of the current year.

2. The ERO will identify 20 to 35 frequency excursion events in each Interconnection for calculating the Frequency Bias Setting and the FRM. If the ERO cannot identify 20 frequency excursion events in a 12-month evaluation period satisfying the criteria below, then similar acceptable events from the subsequent year’s evaluation period will be included with the data set by the ERO for determining compliance.

3. The ERO will use three criteria to determine if an acceptable frequency excursion event for the FRM has occurred:

a. The change in frequency as defined by the difference from the A Value to Point C and the arrested frequency Point C exceeds the excursion threshold values specified for the Interconnection in Table 1 below.

i. The A Value is computed as an average over the period from -16 seconds to 0 seconds before the frequency transient begins to decline.

ii. Point C is the arrested value of frequency observed within 20 seconds following the start of the excursion.

Table 1.1: Interconnection Frequency Excursion Threshold Values

Interconnection A Value to Pt C Point C (Low) Point C (High)

East 0.04Hz < 59.96 > 60.04

West 0.07Hz < 59.95 > 60.05

ERCOT 0.15Hz < 59.90 > 60.10

HQ 0.30Hz < 59.85 > 60.15

b. The time from the start of the rapid change in frequency until the point at which Frequency has stabilized within a narrow range should be less than 18 seconds.

c. If any data point in the B Value average recovers to the A Value, the event will not be included.

4. Pre-disturbance frequency should be relatively steady and near 60.000 Hz for the A Value. The A Value is computed as an average over the period from -16 seconds to 0 seconds before the frequency transient begins to decline. For example, given the choice of the two events below, the one on the right is preferred as the pre-disturbance frequency is stable and also closer to 60 Hz.



Figure 1.1: Pre-disturbance Frequency

5. Excursions that include two or more events that do not stabilize within 18 seconds will not be considered.

6. Frequency excursion events occurring during periods:

a. When large interchange schedule ramping or load change is happening, or

b. Within five minutes of the top of the hour, will be excluded from consideration if other acceptable frequency excursion events from the same quarter are available.

7. The ERO will select the largest (A Value to Point C) two or three frequency excursion events occurring each month. If there are not two frequency excursion events satisfying the selection criteria in a month, then other frequency excursion events should be picked in the following sequence:

a. From the same event quarter of the year.

b. From an adjacent month.

c. From a similar load season in the year (shoulder vs. summer/winter)

d. The largest unused event. As noted earlier, if a total of 20 events are not available in an evaluation year, then similar acceptable events from the next year’s evaluation period will be included with the data set by the ERO for determining Frequency Response Obligation (FRO) compliance. The first year’s small set of data will be reported and used for Bias Setting purposes, but compliance evaluation on the FRO will be done using a 24-month data set. To assist BA preparation for complying with this standard, the ERO will provide quarterly posting of candidate frequency excursion events for the current year FRM calculation. The ERO will post the final list of frequency excursion events used for standard compliance as specified in Attachment A of the standard. The following is a general description of the process that the ERO will use to ensure that BAs can evaluate events during the year in order to monitor their performance throughout the year.

Quarterly The event lists will be reviewed quarterly, with the quarters defined as:

December through February



March through May

June through August

September through November Based on criteria established in this Procedure, events will be selected to populate the FRS Form 1 for each Interconnection. The FRS Form 1's will be posted on the NERC website, in the Resources Subcommittee (RS) area under the title "Frequency Response Standard Resources". Updated FRS Form 1's will be posted at the end of each quarter listed above after a review by the NERC RS and its Frequency Working Group. While the events on this list are expected to be final, as outlined in the selection criteria, additional events may be considered, if the number of events throughout the year do not create a list of at least 20 events. It is intended that this quarterly posting of updates to the FRS Form 1 would allow BAs to evaluate the events throughout the year, lessening the burden when the yearly posting is made.

Annually The final FRS Form 1 for each Interconnection, which would contain the events from all four quarters listed above, will be posted as specified in Attachment A. Each BA reports its previous year’s FRM, Frequency Bias Setting and Frequency Bias type (fixed or variable) to the ERO as specified in Attachment A using the final FRS Form 1. The ERO will check for errors and use the FRS Form 1 data to calculate CPS limits and FROs for the upcoming year. Once the data listed above is fully reviewed, the ERO may adjust the implementation specified in Attachment A for changing the Frequency Bias Settings and CPS limits. This allows flexibility when each BA implements its settings.


Chapter 2: Process for Adjusting Interconnection Minimum

Frequency Bias Setting

This procedure outlines the process the ERO is to use for modifying minimum Frequency Bias Settings to better meet reliability needs. The ERO will adjust the Frequency Bias Setting minimum in accordance with this procedure. The ERO will post the minimum Frequency Bias Setting values on the ERO website along with other balancing standard limits. Under BAL-003-2, the minimum Frequency Bias Settings will be moved toward the natural Frequency Response in each Interconnection. In the first year, the minimum Frequency Bias Setting for each Interconnection is shown in Table 2 below. Each Interconnection Minimum Frequency Bias Setting is based on the sum of the non-coincident peak loads for each BA from the currently available FERC 714 Report or equivalent. This non-coincident peak load sum is multiplied by the percentage shown in Table 2 to get the Interconnection Minimum Frequency Bias Setting. The Interconnection Minimum Frequency Bias Setting is allocated among the BAs on an Interconnection using the same allocation method as is used for the allocation of the Frequency Response Obligation (FRO).

Table 2.1: Frequency Bias Setting Minimums

Interconnection Interconnection Minimum Frequency Bias Setting (in MW/0.1Hz)

Eastern 0.9% of non-coincident peak load

Western 0.9% of non-coincident peak load

ERCOT N/A

HQ N/A

*The minimum Frequency Bias Setting requirement does not apply to a BA that is the only BA in its Interconnection. These BAs are solely responsible for providing reliable frequency control of their Interconnection. These BAs are responsible for converting frequency error into a megawatt error to provide reliable frequency control, and the imposition of a minimum bias setting greater than the magnitude the FRO may have the potential to cause control system hunting, and instability in the extreme.

The ERO, in coordination with the regions of each Interconnection, will annually review Frequency Bias Setting data submitted by BAs. If an Interconnection’s total minimum Frequency Bias Setting exceeds (in absolute value) the Interconnection’s total natural Frequency Response by more (in absolute value) than 0.2 percentage points of peak load (expressed in MW/0.1Hz), the minimum Frequency Bias Setting for BAs within that Interconnection may be reduced (in absolute value) in the subsequent years FRS Form 1 based on the technical evaluation and consultation with the regions affected by 0.1 percentage point of peak load (expressed in MW/0.1Hz) to better match that Frequency Bias Setting and natural Frequency Response. The ERO, in coordination with the regions of each Interconnection, will monitor the impact of the reduction of minimum frequency bias settings, if any, on frequency performance, control performance, and system reliability. If unexpected and undesirable impacts such as, but not limited to, sluggish post-contingency restoration of frequency to schedule or control performance problems occur, then the prior reduction in the minimum frequency bias settings may be reversed, and/or the prospective reduction based on the criterion stated above may not be implemented.


Chapter 3: Interconnection Frequency Response Obligation

Methodology

The Interconnection Resource Loss Protection Criteria (RLPC) is calculated based a resource loss in accordance with the following process:

NERC will request BAs to provide their two largest resource loss values and largest resource loss due to an N-1or N-2 remedial action scheme (RAS) event or largest resource as described above. This will facilitate comparison between the existing Interconnection RLPC values and the RLPC values in use. This data submission will be needed to complete the calculation of the RLPC and IFRO.

BAs determine the two largest resource losses for the next operating year based on a review of the following items:

The two largest Balancing Contingency Events due to a single contingency identified using system models in terms of loss measured by megawatt loss in a normal system configuration (N-0). (An abnormal system configuration is not used to determine the RLPC.)

The two largest units in the BA Area, regardless of shared ownership/responsibility.

The two largest RAS resource losses (if any) which are initiated by single (N-1) contingency events. The BA provides these two numbers determined above as Resource Loss A and Resource Loss B in the FR Form 1. The BA should then provide the largest resource loss due to RAS operations (if any) which is initiated by a multiple contingency (N-2) event (RLPC cannot be lower than this value). If this RAS impacts more than a single BA, one BA is asked to take the lead and sum all resources lost due to the RAS event and provide that information. The calculated RLPC should meet or exceed any credible N-2 resource loss event. The host BA (or planned host BA) where jointly-owned resources are physically located, should be the only BA to report that resource. The full ratings of the resource, not the fractional shares, should be reported. Direct-current (DC) ties to asynchronous resources (such as DC ties between Interconnections, or the Manitoba Hydro Dorsey bi-pole ties to their northern asynchronous generation). DC lines such as the Pacific DC Intertie, which ties two sections of the same synchronous Interconnection together, should not be reported. A single pole block with normal clearing in a monopole or bi-pole high-voltage direct current system is a single contingency. For a hypothetical four-BA Interconnection, Plant 1, in BA1, has two generators rated at 1200 MW each. Plant 2, in BA2 has a generator rated at 1400 MW. BA2’s next largest contingency is 1000 MW. The two largest resource losses for BA3 and BA4 are listed below.

The ERO would apply the RLPC selection methodology described above to determine the RLPC for the Interconnection. Using this methodology, results in the following:

BA1 Resource Loss A = 1200 MW Resource Loss B = 1200 MW Both at Plant 1 (N-2) BA2 Resource Loss A= 1400 MW Resource Loss B = 1000 MW Electrically separate BA3 Resource Loss A = 1000 MW Resource Loss B = 800 MW Electrically separate BA4 Resource Loss A = 1500 MW (DC TIE) Resource Loss B = 500 MW Electrically separate

Chapter 3: Interconnection Frequency Response Obligation Methodology


If only the N-2 Event was applied, the RLPC for the Interconnection would be 2400 MW. The summation of the two largest Interconnection Resource Losses will equal or exceed, but never fall short of, the N-2 Event scenario. In order to evaluate RAS resource loss, single (N-1) and multiple (N-2) contingency events should be evaluated. Hypothetically, in an Interconnection:

In this case, the ERO would determine the RLPC as follows: the summation of the two largest resource losses is 2760 MW. Since the N-2 RAS event exceeds the summation of the two largest single contingency events, the RLPC is the N-2 RAS event, or 2850 MW.

Interconnection RLPC Values Based on initial review, the numbers below would be representative of the RLPC for each Interconnection. Eastern Interconnection: Present RLPC = 4500 MW Load Credit = 0 MW RESOURCE LOSS A = 1732 MW RESOURCE LOSS B = 1477 MW Proposed RLPC = 3209 MW Western Interconnection: Present RLPC = 2626 MW Load Credit = 120 MW RESOURCE LOSS A = 1505 MW RESOURCE LOSS B = 1344 MW N-2 RAS = 2850 MW Proposed RLPC = 2850 MW ERCOT: Present RLPC = 2750 MW Load Credit = 1209 MW RESOURCE LOSS A = 1375 MW RESOURCE LOSS B = 1375 MW Proposed RLPC = 2750 MW

Largest Resource Loss = 1500 MW Second Largest Resource Loss = 1400 MW Summation of two largest resource losses = 2900 MW Interconnection RLPC = 2900 MW

BA1 RAS = 2850 MW N-2 RAS event BA1 Resource Loss A = 1150 MW BA1 Resource Loss B = 800 MW BA2 Resource Loss A = 1380 MW BA2 Resource Loss B = 1380 MW BA3 RAS = 1000 MW N-1 RAS event BA3 Resource Loss A = 800 MW BA3 Resource Loss B = 700 MW



Quebec Interconnection: Present RLPC = 1700 MW Load Credit = 0 MW RESOURCE LOSS A = 1000 MW RESOURCE LOSS B = 1000 MW Proposed RLPC = 2000 MW


Chapter 4: Version History

Version Date Action Change Tracking

II TBD Adopted by NERC BOT Revised

NERC | Report Title | Report Date I

Version II

Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard

NERC | Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard | Version II | 2019 NERC | Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard |

ii

Table of Contents

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

Introduction ................................................................................................................................................................. iivv

Chapter 1: Event Selection Process ................................................................................................................................. 1

Event Selection Objectives .......................................................................................................................................... 1

Event Selection Criteria ............................................................................................................................................... 1

Quarterly .................................................................................................................................................................. 3

Annually ................................................................................................................................................................... 3

Chapter 2: Process for Adjusting Interconnection Minimum Frequency Bias Setting .................................................... 4

Chapter 3: Interconnection Frequency Response Obligation Methodology ................................................................ 65


iii

Preface

The vision for the Electric Reliability Organization (ERO) Enterprise, which is comprised of the North American Electric Reliability Corporation (NERC) and the seven Regional Entities (REs), is a highly reliable and secure North American bulk power system (BPS). Our mission is to assure the effective and efficient reduction of risks to the reliability and security of the grid. The North American BPS is divided into seven RE boundaries as shown in the map and corresponding table below. The multicolored area denotes overlap as some load-serving entities participate in one Region while associated Transmission Owners/Operators participate in another.

FRCC Florida Reliability Coordinating Council

MRO Midwest Reliability Organization

NPCC Northeast Power Coordinating Council

RF ReliabilityFirst

SERC SERC Reliability Corporation

Texas RE Texas Reliability Entity

WECC Western Electricity Coordinating CouncilWECC


iv

Introduction

This procedure (Procedure) outlines the Electric Reliability Organization (ERO) process for supporting the Frequency Response Standard (FRS). A Procedure revision request for revisions may be submitted to the Operating Committee (OC) of the ERO for consideration. The revision request must provide a technical justification for the suggested modification. The ERO shall publicly post the suggested modification for a 45-day formal comment period and discuss the revision request in a public meeting of the ERO OC. The ERO will make a recommendation to the NERC BOTBoard of Trustees (BOTBoard), which may adopt the revision request, reject it, or adopt it with modifications. Any approved revision to this Procedure shall be filed with the Federal Energy Regulatory Commission (FERC) for informational purposes. BAL-003-2 sets Interconnection Frequency Response Obligation (IFRO) to preset values subject to annual review. This procedure establishes the methods to be used for the annual review until Phase 2 of the SAR for Project 2017-01 has been addressed. If Frequency Response Measure (FRM) for the Eastern Interconnection degrades more than 10 percent% in a year, the ERO will halt the reduction in IFRO until such time as a determination can be made as to the cause of the degradation.

NERC | Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard | Version II | 2019 NERC | Report Title | Report Date

1


Event Selection Objectives The goals of this procedure are to outline a transparent, repeatable process to annually identify a list of frequency events to be used by Balancing Authorities (BA) to calculate their Frequency Response to determine:

Whether the Balancing Authority (BA) or Frequency Response Sharing Group (FRSG) met its Frequency Response Obligation, and

An appropriate fixed Frequency Bias Setting.

Event Selection Criteria

1. The ERO will use the following criteria to select FRS frequency excursion events for analysis. The events that best fit the criteria will be used to support the FRS. The evaluation period for performing the annual Frequency Bias Setting and the Frequency Response Measure (FRM) calculation is December 1 of the prior year through November 30 of the current year.

2. The ERO will identify 20 to 35 frequency excursion events in each Interconnection for calculating the Frequency Bias Setting and the FRM. If the ERO cannot identify 20 frequency excursion events in a 12- month evaluation period satisfying the criteria below, then similar acceptable events from the subsequent year’s evaluation period will be included with the data set by the ERO for determining FRS compliance. This is described later.

3. The ERO will use three criteria to determine if an acceptable frequency excursion event for the FRM has occurred:

a. The change in frequency as defined by the difference from the A Value to Point C and the arrested frequency Point C exceeds the excursion threshold values specified for the Interconnection in Table 1 below.

i. The A Value is computed as an average over the period from -16 seconds to 0 seconds before the frequency transient begins to decline.

ii. Point C is the arrested value of frequency observed within 12 20 seconds following the start of the excursion.

Table 1.1: Interconnection Frequency Excursion Threshold Values

Interconnection A Value to Pt C Point C (Low) Point C (High)

East 0.04Hz < 59.96 > 60.04

West 0.07Hz < 59.95 > 60.05

ERCOT 0.15Hz < 59.90 > 60.10

HQ 0.30Hz < 59.85 > 60.15

b. The time from the start of the rapid change in frequency until the point at which Frequency has stabilized within a narrow range should be less than 18 seconds.

c. If any data point in the B Value average recovers to the A Value, the event will not be included.


NERC | Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard | Version II | 2019

NERC | Report Title | Report Date 2

4. Pre-disturbance frequency should be relatively steady and near 60.000 Hz for the A Value. The A Value is computed as an average over the period from -16 seconds to 0 seconds before the frequency transient begins to decline. For example, given the choice of the two events below, the one on the right is preferred as the pre-disturbance frequency is stable and also closer to 60 Hz.

Figure 1.1: Pre-disturbance Frequency

5. Excursions that include 2 two or more events that do not stabilize within 18 seconds will not be considered.

6. Frequency excursion events occurring during periods:

a. when large interchange schedule ramping or load change is happening, or

b. within 5 five minutes of the top of the hour, will be excluded from consideration if other acceptable frequency excursion events from the same quarter are available.

7. The ERO will select the largest (A Value to Point C) 2 or 3two or three frequency excursion events occurring each month. If there are not 2 two frequency excursion events satisfying the selection criteria in a month, then other frequency excursion events should be picked in the following sequence:

a. From the same event quarter of the year.

b. From an adjacent month.

c. From a similar load season in the year (shoulder vs. summer/winter)

d. The largest unused event. As noted earlier, if a total of 20 events are not available in an evaluation year, then similar acceptable events from the next year’s evaluation period will be included with the data set by the ERO for determining Frequency Response Obligation (FRO) compliance. The first year’s small set of data will be reported and used for Bias Setting purposes, but compliance evaluation on the FRO will be done using a 24-month data set.

To assist Balancing AuthorityBA preparation for complying with this standard, the ERO will provide quarterly posting of candidate frequency excursion events for the current year FRM calculation. The ERO will post the final list of frequency excursion events used for standard compliance as specified in Attachment A of BAL-003-1the standard.




The following is a general description of the process that the ERO will use to ensure that BAs can evaluate events during the year in order to monitor their performance throughout the year.

Monthly Candidate events will be initially screened by the "Frequency Event Detection Methodology" shown on the following link located on the NERC Resources Subcommittee area of the NERC website: http://www.nerc.com/docs/oc/rs/Frequency_Event_Detection_Methodology_and_Criteria_Oct_2011.pdf. Each month's list will be posted by the end of the following month on the NERC website, http://www.nerc.com/filez/rs.html and listed under "Candidate Frequency Events".

Quarterly The monthly event lists will be reviewed quarterly, with the quarters defined as:

December through February

March through May

June through August

September through November Based on criteria established in the this Procedure"Procedure for ERO Support of Frequency Response and Frequency Bias Setting Standard", events will be selected to populate the FRS Form 1 for each Interconnection. The FRS Form 1's will be posted on the NERC website, in the Resources Subcommittee (RS) area under the title "Frequency Response Standard Resources". Updated FRS Form 1's will be posted at the end of each quarter listed above after a review by the NERC Resources Subcommittee (RS)' and its Frequency Working Group. While the events on this list are expected to be final, as outlined in the selection criteria, additional events may be considered, if the number of events throughout the year do not create a list of at least 20 events. It is intended that this quarterly posting of updates to the FRS Form 1 would allow BAs to evaluate the events throughout the year, lessening the burden when the yearly posting is made.

Annually The final FRS Form 1 for each Interconnection, which would contain the events from all four quarters listed above, will be posted as specified in Attachment A. Each Balancing AuthorityBA reports its previous year’s Frequency Response Measure (FRM), Frequency Bias Setting and Frequency Bias type (fixed or variable) to the ERO as specified in Attachment A using the final FRS Form 1. The ERO will check for errors and use the FRS Form 1 data to calculate CPS limits and FROs for the upcoming year. Once the data listed above is fully reviewed, the ERO may adjust the implementation specified in Attachment A for changing the Frequency Bias Settings and CPS limits. This allows flexibility in when each BA implements its settings.


4

Chapter 2: Process for Adjusting Interconnection Minimum

Frequency Bias Setting

This procedure outlines the process the ERO is to use for modifying minimum Frequency Bias Settings to better meet reliability needs. The ERO will adjust the Frequency Bias Setting minimum in accordance with this procedure. The ERO will post the minimum Frequency Bias Setting values on the ERO website along with other balancing standard limits. Under BAL-003-12, the minimum Frequency Bias Settings will be moved toward the natural Frequency Response in each interconnectionInterconnection. In the first year, the minimum Frequency Bias Setting for each interconnection Interconnection is shown in Table 2 below. Each Interconnection Minimum Frequency Bias Setting is based on the sum of the non-coincident peak loads for each BA from the currently available FERC 714 Report or equivalent. This non-coincident peak load sum is multiplied by the percentage shown in Table 2 to get the Interconnection Minimum Frequency Bias Setting. The Interconnection Minimum Frequency Bias Setting is allocated among the BAs on an interconnection Interconnection using the same allocation method as is used for the allocation of the Frequency Response Obligation (FRO).

Table 2.1: Frequency Bias Setting Minimums

Interconnection Interconnection Minimum Frequency Bias Setting (in MW/0.1Hz)

Eastern 0.9% of non-coincident peak load

Western 0.9% of non-coincident peak load

ERCOT N/A

HQ N/A

*The minimum Frequency Bias Setting requirement does not apply to a Balancing AuthorityBA that is the only Balancing AuthorityBA in its Interconnection. These Balancing AuthoritiesBAs are solely responsible for providing reliable frequency control of their Interconnection. These Balancing AuthoritiesBAs are responsible for converting frequency error into a megawatt error to provide reliable frequency control, and the imposition of a minimum bias setting greater than the magnitude the Frequency Response ObligationFRO may have the potential to cause control system hunting, and instability in the extreme.

The ERO, in coordination with the regions of each interconnectionInterconnection, will annually review Frequency Bias Setting data submitted by BAs. If an Interconnection’s total minimum Frequency Bias Setting exceeds (in absolute value) the Interconnection’s total natural Frequency Response by more (in absolute value) than 0.2 percentage points of peak load (expressed in MW/0.1Hz), the minimum Frequency Bias Setting for BAs within that Interconnection may be reduced (in absolute value) in the subsequent years FRS Form 1 based on the technical evaluation and consultation with the regions affected by 0.1 percentage point of peak load (expressed in MW/0.1Hz) to better match that Frequency Bias Setting and natural Frequency Response. The ERO, in coordination with the rRegions of each Interconnection, will monitor the impact of the reduction of minimum frequency bias settings, if any, on frequency performance, control performance, and system reliability. If unexpected and undesirable impacts such as, but not limited to, sluggish post-contingency restoration of frequency to schedule or control performance problems occur, then the prior reduction in the minimum frequency bias settings may be reversed, and/or the prospective reduction based on the criterion stated above may not be implemented.

Chapter 2: Process for Adjusting Interconnection Minimum Frequency Bias Setting




6

Chapter 3: Interconnection Frequency Response Obligation

Methodology

The Interconnection Resource Loss Protection Criteria (RLPC) is calculated based a resource loss in accordance with the following process:

NERC will request BAs to provide their two largest resource loss values and largest resource loss due to an N-1or N-2 remedial action scheme (RAS) event or largest resource as described above. This will facilitate comparison between the existing Interconnection RLPC values and the RLPC values in use. This data submission will be needed to complete the calculation of the RLPC and IFRO.

BAs determine the two largest resource losses for the next operating year based on a review of the following items:

The two largest Balancing Contingency Events due to a single contingency identified using system models in terms of loss measured by megawatt loss in a normal system configuration (N-0). (An abnormal system configuration is not used to determine the RLPC.)

The two largest units in the BA Area, regardless of shared ownership/responsibility.

The two largest Remedial Action Scheme (RAS) resource losses (if any) which are initiated by single (N-1) contingency events.

The BA provides these two numbers determined above as Resource Loss A and Resource Loss B in the FR Form 1. The BA should then provide the largest resource loss due to RAS operations (if any) which is initiated by a multiple contingency (N-2) event (RLPC cannot be lower than this value). If this RAS impacts more than a single BA, one BA is asked to take the lead and sum all resources lost due to the RAS event and provide that information. The calculated RLPC should meet or exceed any credible N-2 resource loss event. The host BA (or planned host BA) where jointly-owned resources are physically located, should be the only BA to report that resource. The full ratings of the resource, not the fractional shares, should be reported. Direct-current (DCdc) ties to asynchronous resources (such as DCdc ties between Interconnections, or the Manitoba Hydro Dorsey bi-pole ties to their northern asynchronous generation). DC lines such as the Pacific DC Intertie, which ties two sections of the same synchronous Interconnection together, should not be reported. A single pole block with normal clearing in a monopole or bi-pole high-voltage direct current system is a single contingency. For a hypothetical four-BA Interconnection, Plant 1, in BA1, has two generators rated at 1200 MW each. Plant 2, in BA2 has a generator rated at 1400 MW. BA2’s next largest contingency is 1000 MW. The two largest resource losses for BA3 and BA4 are listed below.

BA1 Resource Loss A = 1200 MW Resource Loss B = 1200 MW Both at Plant 1 (N-2) BA2 Resource Loss A= 1400 MW Resource Loss B = 1000 MW Electrically separate BA3 Resource Loss A = 1000 MW Resource Loss B = 800 MW Electrically separate BA4 Resource Loss A = 1500 MW (DC TIE) Resource Loss B = 500 MW Electrically separate




The ERO would apply the RLPC selection methodology described above to determine the RLPC for the Interconnection. Using this methodology, results in the following: If only the N-2 Event was applied, the RLPC for the Interconnection would be 2400 MW. The summation of the two largest Interconnection Resource Losses will equal or exceed, but never fall short of, the N-2 Event scenario. In order to evaluate RAS resource loss, single (N-1) and multiple (N-2) contingency events should be evaluated. Hypothetically, in an Interconnection: This

procedure outlines the process the ERO is to use for determining the Interconnection Frequency Response Obligation (IFRO). The following are the formulae that comprise the calculation of the IFROs.

𝐷𝐹𝐵𝑎𝑠𝑒 = 𝐹𝑆𝑡𝑎𝑟𝑡 − 𝑈𝐹𝐿𝑆

𝐷𝐹𝐶𝐶 = 𝐷𝐹𝐵𝑎𝑠𝑒 − 𝐶𝐶𝐴𝑑𝑗

𝐷𝐹𝐶𝐵𝑅 = 𝐷𝐹𝐶𝐶

𝐶𝐵𝑅

𝑀𝐷𝐹 = 𝐷𝐹𝐶𝐵𝑅 − 𝐵𝐶′𝐴𝑑𝑗

𝐴𝑅𝐶𝐶 = 𝑅𝐶𝐶 − 𝐶𝐿𝑅

𝐼𝐹𝑅𝑂 = 𝐴𝑅𝐶𝐶

10 ∗ 𝑀𝐷𝐹

Where:

DFBase is the base delta frequency.

FStart is the starting frequency determined by the statistical analysis.

UFLS is the highest UFLS trip setpoint for the interconnection.

Largest Resource Loss = 1500 MW Second Largest Resource Loss = 1400 MW Summation of two largest resource losses = 2900 MW Interconnection RLPC = 2900 MW

BA1 RAS = 2850 MW N-2 RAS event BA1 Resource Loss A = 1150 MW BA1 Resource Loss B = 800 MW BA2 Resource Loss A = 1380 MW BA2 Resource Loss B = 1380 MW BA3 RAS = 1000 MW N-1 RAS event BA3 Resource Loss A = 800 MW BA3 Resource Loss B = 700 MW




CCAdj is the adjustment for the differences between 1-second and sub-second Point C observations for frequency events. A positive value indicates that the sub-second C data is lower than the 1-second data.

DFCC is the delta frequency adjusted for the differences between 1-second and sub-second Point C observations for frequency events.

CBR is the statistically determined ratio of the Point C to Value B.

DFCBR is the delta frequency adjusted for the ratio of the Point C to Value B.

BC’ADJ is the statistically determined adjustment for the event nadir being below the Value B (Eastern Interconnection only) during primary frequency response withdrawal.

MDF is the maximum allowable delta frequency.

RCC is the resource contingency criteria.

CLR is the credit for load resources.

ARCC is the adjusted resource contingency criteria adjusted for the credit for load resources.

IFRO is the interconnection frequency response obligation. In this case, the ERO would determine the RLPC as follows: the summation of the two largest resource losses is 2760 MW. Since the N-2 RAS event exceeds the summation of the two largest single contingency events, the RLPC is the N-2 RAS event, or 2850 MW.

Interconnection RLPC Values Based on initial review, the numbers below would be representative of the RLPC for each Interconnection. Eastern Interconnection: Present RLPC = 4500 MW Load Credit = 0 MW RESOURCE LOSS A = 1732 MW RESOURCE LOSS B = 1477 MW Proposed RLPC = 3209 MW Western Interconnection: Present RLPC = 2626 MW Load Credit = 120 MW RESOURCE LOSS A = 1505 MW RESOURCE LOSS B = 1344 MW N-2 RAS = 2850 MW Proposed RLPC = 2850 MW ERCOT: Present RLPC = 2750 MW Load Credit = 1209 MW RESOURCE LOSS A = 1375 MW RESOURCE LOSS B = 1375 MW Proposed RLPC = 2750 MW Quebec Interconnection: Present RLPC = 1700 MW Load Credit = 0 MW RESOURCE LOSS A = 1000 MW RESOURCE LOSS B = 1000 MW




Proposed RLPC = 2000 MW




Version History

Version Date Action Change Tracking II TBD Adopted by NERC BOT Revised

Operating Committee Reliability Guideline and Reference Document Quick Reference Guide The NERC Operating Committee (OC), Planning Committee (PC) and Critical Infrastructure Protection Committee (CIPC) develop Reliability (OC and PC) and Security (CIPC) Guidelines, which include the collective experience, expertise and judgment of the industry. The objective of the reliability guidelines is to distribute key practices and information on specific issues critical to promote and maintain a highly reliable and secure bulk power system (BPS). Reliability guidelines are not binding norms or parameters to the level that compliance to NERC’s Reliability Standards are monitored or enforced. Rather, their incorporation into industry practices are strictly voluntary. Reviewing, revising, or developing a program using these practices is highly encouraged.

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https://www.nerc.com/comm/OC_Reliability_Guidelines_DL/Inverter-Based_Resource_Performance_Guideline.pdf



Reliability Guideline and Reference Document – Quick Reference Guide 2


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asynchronously connected to the grid and are either completely or partially interfaced with the BPS through power electronics, hence referred to as inverter-based resources. The power electronics aspects of these generating resources present new opportunities in terms of grid control and response to abnormal grid conditions. Regardless of the type of resource, it is paramount that all BPS-connected resources are capable of providing ERSs 3 and operate in a manner that supports BPS reliability. NERC, as the ERO of North America, is tasked with assuring reliability of the North American BPS and is continually assessing the impacts of the changing resource mix. A critical component to these assessments is developing guidance and recommended practices for the performance of resources when connected to the BPS. This Reliability Guideline provides a set of recommended performance specifications for inverter-based resources

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Reliability Guideline and Reference Document – Quick Reference Guide 3


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Subcommittee (ORS). RC Reliability Plans are used by RCs to document each RC’s plan for meeting the obligations of the functional area and ensure that the plan is adequately coordinated with the entities within the RC area and neighboring entities. RCs may develop individual RC Reliability Plans or opt to include multiple RCs, such as RCs of a particular Region, within a single Reliability Plan.