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Agenda Standards Committee Meeting July 19, 2017 | 1:00 p.m. to 4:00 p.m. Eastern Dial-in: 1-415-655-0002 | Access Code: 735 920 686 | Meeting Password: 071917 Click here for WebEx Access Introduction and Chair’s Remarks NERC Antitrust Compliance Guidelines and Public Announcement* Agenda Items

1. Review July 19 Agenda ― (Approve) (B. Murphy) (1 minute)

2. Consent Agenda ― (Approve) (B. Murphy) (1 minute)

a. June 14, 2017 Standards Committee Meeting Minutes* ― (Approve)

b. Standards Committee Chair and Vice Chair Election* ― (Approve)

c. Project Management and Oversight Subcommittee Vice Chair Selection* ― (Endorse)

d. Errata for VAR-501-WECC-3.1* ― (Approve)

e. BAL-002-2 & BAL-003-1.1 SAR Drafting Team Nominations* ― (Approve)

3. Upcoming Standards Projects or Issues ― (Update)

a. Three-Month Outlook* (S. Noess; B. Murphy) (10 minutes)

4. Projects Under Development ― (Review)

a. Project Tracking Spreadsheet (C. Yeung) (10 minutes)

b. Projected Posting Schedule (S. Noess) (5 minutes)

5. 2018 Standards Committee Meeting Dates* ― (Approve) (C. Larson) (5 minutes)

6. Project 2016-02 Modifications to CIP Standards CIP-012-1* ― (Authorize) (S. Cavote) (10 minutes)

7. Project 2016-04 Modifications to PRC-025-1* ― (Authorize) (S. Kim) (10 minutes)

8. Project 2017-03 FAC-008-3 Periodic Review* CONFIDENTIAL ― (Appoint) (S. Cavote) (10 minutes)

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Agenda - Standards Committee Meeting | July 19, 2017 2

9. Project 2017-04 Periodic Review of INT Standards* CONFIDENTIAL ― (Appoint) (S. Cavote) (10 minutes)

10. Project 2017-05 Periodic Review of NUC-001-3* CONFIDENTIAL ― (Appoint) (S. Cavote) (10 minutes)

11. Project 2017-07 Standards Alignment with Registration* ― (Authorize) (S. Cavote) (10 minutes)

12. Standard Authorization Request for BAL-003-1.1* ― (Authorize) (S. Noess) (10 minutes)

13. Request for Interpretation and Standard Authorization Request PRC-024*― (Reject) (S. Kim) (10 minutes)

14. Request for Interpretation of INT-004-3.1*― (Reject) (S. Kim) (10 minutes)

15. Request for Interpretation of PRC-024*― (Reject) (S. Kim) (10 minutes)

16. Standard Authorization Request for CIP-014-3* ― (Authorize) (S. Noess) (10 minutes)

17. Subcommittee Reports and Updates

a. Project Management and Oversight Subcommittee ― (Update) (C. Yeung) (5 minutes)

b. Process Subcommittee* ― (Update) (B. Li) (5 minutes)

18. Legal Update, Upcoming Standards Filings* ― (Review) (L. Perotti) (5 minutes)

19. Informational Items ― (Enclosed)

a. Standards Committee Expectations*

b. 2017 Meeting Dates and Locations*

c. 2017 Standards Committee Roster*

d. Highlights of Parliamentary Procedure*

20. Adjourn

*Background materials included.

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.

NERC Antitrust Compliance Guidelines 2

• 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. 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 Announcements

Conference call: Participants are reminded that this conference call is public. The access number 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.

Minutes Standards Committee Meeting June 14, 2017 | 10:00 a.m. to 3:00 p.m. Eastern B. Murphy, chair, called the meeting of the Standards Committee (SC or the Committee) to order on June 14, 2017, at 10:00 a.m. Eastern. After the roll call by C. Larson, secretary, meeting quorum was declared. The SC member attendance and proxy sheet is attached hereto as Attachment 1. NERC Antitrust Compliance Guidelines and Public Announcement Committee Secretary called attention to the NERC Antitrust Compliance Guidelines and the public meeting notice. He asked that any questions regarding the NERC Antitrust Compliance Guidelines be directed to NERC’s General Counsel, Charles Berardesco. Introduction and Chair’s Remarks B. Murphy welcomed the Committee and guests. He introduced M. Marchand as the newest SC member. B. Murphy requested SC members not discuss the Cybersecurity Supply Chain Management standard, since it is currently in open ballot. H. Gugel provided an update on Mexico partnership, stating they are reviewing an initial list of standards that Mexico may adopt. He said cost effectiveness initiatives remain a priority with the NERC Board of Trustees.

Review June 14, 2017 Agenda (agenda item 1) Approved by unanimous consent, with striking of items 2c and 11.

Consent Agenda (agenda item 2) Motion to adopt April 19, 2017 Standards Committee Meeting Minutes

Approved by unanimous consent. Motion to adopt May 1, 2017 Standards Committee Special Call Minutes

Approved by unanimous consent.

Upcoming Standards Projects or Issues (agenda item 3) Three-Month Outlook

S. Noess provided highlights of the Three-Month Outlook. S. Rueckert asked about staggering industry postings to minimize the impact on industry resources given the amount of upcoming projects. S. Noess committed to use the SC’s guidelines on posting, and properly space the posting of projects. Projects Under Development (agenda item 4) C. Yeung reviewed the Project Tracking Spreadsheet (Project Tracking Spreadsheet).

Agenda Item 2a Standards Committee July 19, 2017

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S. Noess reviewed the Projected Posting Schedule (Projected Posting Schedule). There were no comments or questions from the SC or observers.

Project 2013-03 Geomagnetic Disturbance Mitigation (agenda item 5a) A. Gallo made a motion to accept the action item with an additional clarification in underline; B. Hampton seconded. The motion was as follows:

Authorize posting proposed Reliability Standard TPL-007-2, the associated Implementation Plan, Violation Risk Factors (VRFs), and Violation Severity Levels (VSLs) for a 45-day formal comment period with parallel initial ballot and nonbinding poll during the last 10 days of the comment period, provided that the Epeak multiplier value (reference geoelectric field value for the supplemental GMD event) in Attachment 1 of TPL-007-2 is 17 V/km or less.

The Committee voted down the motion with 9 negative and 8 affirmative votes. S. Bodkin made a second motion to accept the action item with an additional clarification in underline; B. Li seconded. The motion was as follows:

Authorize posting proposed Reliability Standard TPL-007-2, the associated Implementation Plan, Violation Risk Factors (VRFs), and Violation Severity Levels (VSLs) for a 45-day formal comment period with parallel initial ballot and nonbinding poll during the last 10 days of the comment period, provided that the Epeak multiplier value (reference geoelectric field value for the supplemental GMD event) in Attachment 1 of TPL-007-2 is the only change that can be made by the standard drafting team prior to posting.

The Committee approved the motion with A. Gallo, B. Lawson, and S. Miller objecting, and no abstentions.

Project 2013-03 Geomagnetic Disturbance Mitigation (agenda item 5b) G. Zito made the motion to accept the action item as written; R. Crissman seconded. The motion was as follows:

Approve the following project schedule for Project 2013-03 Geomagnetic Disturbance Mitigation:

1. Finalization of the Standard Authorization Request (completed)

2. Initial Posting and Ballot of Standard(s) (June 2017)

3. Additional Postings and Ballots (as needed)

4. Final Ballot (March 2018)

The Committee approved the motion with no objections or abstentions.

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BAL-002-2 Standard Authorization Request (agenda item 6) B. Hampton made the motion to accept the action item as written; B. Li seconded. B. Murphy brought the motion to a vote. The motion was as follows:

Authorize the posting of the BAL-002-2 Standard Authorization Request (SAR), developed in response to FERC Order No. 835 directives, for a 30-day informal comment period and solicit for SAR drafting team members.

The Committee approved the motion with no objections.

BAL-003-1.1 Standard Authorization Request (agenda item 7) C. Gowder made the motion to accept the action item as written; R. Crissman seconded. H. Illian noted a second SAR had been submitted that is being reviewed by NERC. H. Gugel commented that additional technical background was requested from the SAR submitter. In the event the SAR is resubmitted at a future date, he cautioned on having multiple SAR drafting teams for the same standard. The motion was as follows:

Authorize the posting of a BAL-003-1.1 Standard Authorization Request (SAR) for Project 2017-01 for a 30-day formal comment period. Authorize the posting for nominations of a SAR drafting team to consider stakeholder comments over a 14-day nomination period.


Project 2016-EPR-01 Enhanced Periodic Review of PER-003-1 and PER-004-2, Standard Authorization Requests, and Standard Drafting Team (agenda item 8) B. Li made the motion to accept the action item as written; R. Crissman seconded. The motion was as follows:

Accept the Periodic Review Team’s recommendation to revise PER-003-1, retire PER-004-2, and authorize the posting of PER-003-1 and PER-004-2 Standard Authorization Requests (SAR) for an initial 30-day informal comment period. Appoint the Project 2016-EPR-01 Enhanced Periodic Review Team (PRT) as the SAR drafting team.

The Committee approved the motion with no objections. The following SDT members were appointed.

• Patti Metro, National Rural Electric Cooperative Association

• Lauri Jones, Pacific Gas and Electric Company

• Heather Morgan, EDP Renewables North America LLC


• Jeffrey Sunvick, Western Area Power Administration

• Jimmy Womack, Southwest Power Pool

• Brad Perrett, Minnesota Power

• Carolyn White-Wilson, Duke Energy

• Michael B. Hoke, PJM Interconnection

• Danny W. Johnson, Excel Energy

Project 2016-EPR-02 Enhanced Periodic Review of Voltage and Reactive Standards (agenda item 9) G. Zito made the motion to accept the action item as written; R. Crissman seconded. J. Seelke shared that the Attachment 5 comments could have been addressed more thoroughly by the periodic review team (PRT). S. Solis explained the process the PRT followed, and some of the feedback they had received from industry. S. Miller suggested an update to the PRT worksheet, which will be addressed by an upcoming Standards Committee Process Subcommittee project. The motion was as follows:

Accept the recommendation of the periodic review team (PRT) to reaffirm Reliability Standards VAR-001-4.1 (Voltage and Reactive Control) and VAR-002-4 (Generator Operation for Maintaining Network Voltage Schedules) and submit the reaffirmation to the Board of Trustees for adoption.


Project 2016-EPR-02 Errata of VAR-001-4.1 and VAR-002-4 (agenda item 10) G. Zito made the motion to accept the action item as written; B. Hampton seconded. The motion was as follows:

Approve the errata revisions based on the recommendations of the periodic review team (PRT) review of Reliability Standards VAR-001-4.1 (Voltage and Reactive Control) and VAR-002-4 (Generator Operation for Maintaining Network Voltage Schedules).


Technical Rationale for Reliability Standards (agenda item 12) G. Zito made the motion to accept the action item with a friendly amendment in underline; C. Yeung seconded and also accepted the friendly amendment. A. Gallo requested more background information about Technical Rationale. B. Lawson asked about the Technical Rationale review process, and he suggested an effort for additional industry outreach. H. Gugel provided a high level overview of the history, distinguished between Compliance Guidance, Guidelines and Technical Basis, and Technical


Rationale. B. Li suggested a few refinements should be considered before finalizing the processes. The motion was as follows:

Endorse the “Technical Rationale for Reliability Standards” document and its approach for the development of technical rationale during Reliability Standards development. The SCEC and NERC staff will coordinate an industry outreach effort explaining background and seeking process input for Technical Rationale, such as an industry poll and webinar, then report back to the SC in Fall 2017.

The Committee approved the motion with no objections or abstentions. Request for Interpretation EOP-008-1 Requirement R4 (agenda item 13) G. Zito made the motion to accept the action item as written; S. Miller seconded. C. Gowder requested a background on the conversations that were had with the requestor. S. Noess provided a brief explanation of the discussion with the requestor. The motion was as follows:

Reject the Request for Interpretation (RFI) of EOP-008-1 submitted by Texas-New Mexico Power Company, on the grounds that the meaning of the Reliability Standard language at issue is plain on its face.

The Committee approved the motion with no objections or abstentions. Request for Interpretation PRC-006-2 Requirement R9 (agenda item 14) G. Zito made the motion to accept the action item as written; A. Gallo seconded. The SC chair noted he would follow up with NERC staff to determine when this standard is up for Periodic Review, and determine if any further action is necessary. The motion was as follows:

Reject the Request for Interpretation (RFI) of PRC-006-2 submitted by Utility Services, Inc., pursuant to Section 7.0 of the Standard Processes Manual, on the grounds that the meaning of the Reliability Standard language at issue is plain on its face, and the question has already been addressed in the record.

The Committee approved the motion with no objections or abstentions. Project to Review/Revise the Periodic Review Template (agenda item 15) B. Li made the motion to accept the action item as written; B. Hampton seconded. The motion was as follows:

Endorse the attached scope document for a project led by the Standards Committee Process Subcommittee to review the Periodic Review Template and recommend modifications to the SC for adoption. The Committee approved the motion with no objections or abstentions.


Subcommittee Reports and Updates (agenda item 16)

Project Management and Oversight Subcommittee C. Yeung provided an update of Project Management and Oversight Subcommittee (PMOS) activities. He provided detail on how PMOS develops a baseline project timeline, and why changes are made to a baseline timelines. A PMOS vice chair selection will be presented to the SC at the July meeting.

Process Subcommittee B. Li provided an update of Standards Committee Process Subcommittee work activities. He updated the group on the recent Standard Processes Manual ballot, comments, and upcoming revisions.

Legal Update (agenda item 17) L. Perotti provided her update regarding recent and upcoming standards filings. Informational Items (agenda item 18) No discussion on informational items. Adjourn B. Murphy thanked the Committee members and adjourned the meeting at 1:17 p.m. Eastern.

Attachment I

Segment and Term Representative Organization Proxy Present (Member or

Proxy)

Chair 2016‐17

Brian Murphy Senior Attorney

NextEra Energy, Inc. Yes

Vice‐Chair 2016‐17

Michelle D’Antuono Manager, Energy

Occidental Energy Ventures, LLC

Yes

Segment 1‐2016‐17 Laura Lee Manager of ERO Support and Event Analysis, System Operations

Duke Energy Yes

Segment 1‐2017‐18 Sean Bodkin NERC Compliance Policy Manager

Dominion Resources Services, Inc.

Yes

Segment 2‐2016‐17 Ben Li Consultant

Independent Electric System Operator

Yes

Segment 2‐2017‐18 Charles Yeung Executive Director Interregional Affairs

Southwest Power Pool Yes

Segment 3‐2016‐17 Scott Miller Manager Regulatory Policy

MEAG Power Yes

Segment 3‐2017‐18 John Bussman Manager, Reliability Compliance

Associated Electric Cooperative, Inc.

Mark Riley Yes

Segment 4‐2016‐17 Chris Gowder Regulatory Compliance Specialist

Florida Municipal Power Agency

Yes

Segment 4‐2017‐18 Barry Lawson Associate Director,

Power Delivery and Reliability

National Rural Electric Cooperative Association

Yes

Segment 5‐2016‐17 Randy Crissman Vice President – Technical Compliance

New York Power Authority Yes

Segment 5‐2017‐18 Amy Casuscelli Sr. Reliability Standards Analyst

Xcel Energy Yes

Standards Committee Attendance – June 14, 2017

Segment and Term Representative Organization Proxy Present (Member or

Proxy)

Segment 6‐2016‐17 Andrew Gallo Director, Reliability Compliance

City of Austin dba Austin Energy

Yes

Segment 6‐2017‐18 Brenda Hampton Regulatory Policy

Vistra Energy – Luminant Energy Company LLC

Yes

Segment 7‐2016‐17 Frank McElvain Senior Manager, Consulting

Siemens Power Technologies International

No

Segment 7‐2017‐18 VACANT N/A

Segment 8‐2016‐17 Robert Blohm Managing Director

Keen Resources Ltd. Howard Illian Yes

Segment 8‐2017‐18 David Kiguel Independent Yes

Segment 9‐2016‐17 Alexander Vedvik Senior Electrical Engineer

Public Service Commission of Wisconsin

Yes

Segment 9‐2017‐18 Michael Marchand Senior Policy Analyst

Arkansas Public Service Commission

Yes

Segment 10‐2016‐17 Guy Zito Assistant Vice President of Standards

Northeast Power Coordinating Council

Yes

Segment 10‐2017‐18 Steven Rueckert Director of Standards

Western Electricity Coordinating Council

Yes

Standards Committee Attendance – June 14, 2017

Agenda Item 2b Standards Committee July 19, 2017

Process for Election of Chair and Vice Chair

Action Approve the following approach1 for the election of chair and vice chair of the Standards Committee (SC) two-year terms starting January 1, 2018 and ending December 31, 2019: 1. The formation of a nomination committee, consisting of the three “at large” Standards

Committee Executive Committee members (i.e., Randy Crissman, Guy Zito, and Sean Bodkin). If any of these members decide to run for chair or vice chair, they shall resign from the nominating committee. If a member(s) of the nominating committee decide to run for chair or vice chair, the chair of the SC will solicit, via an email announcement, SC member(s) to serve on the nominating committee, so the nominating committee is at its full three member complement.

2. The nominating committee shall solicit nominations for chair and vice chair from July 20,

2017 to August 21, 2017, with the understanding that nominations may be selected from the floor on the day of the election pursuant to Section 5 (1) of the SC Charter. The nominating committee shall develop a questionnaire to solicit the qualifications from the nominees. Nominations may be made via another SC member or via self-nominations. Any member nominated by another SC member will be requested to confirm they accept the nomination.

3. No later than August 25, 2017, the nominating committee shall provide the SC a list

(via email) of members who have submitted a self-nomination or been nominated by a member for chair and vice chair, along with the qualifications of the nominees. The nominating committee’s email of nominees and qualifications shall also be sent to the Chair of the Board of Trustees’ Standards Oversight and Technology Committee.

4. At the September 7, 2017 SC face-to-face meeting, elections for the chair and vice chair

will be conducted immediately after the consent agenda is completed. The elections shall be accomplished as follows:

a. The nominating committee will ask if there are any nominations from the floor. If

there is a nomination from the floor, the nominee shall be provided five minutes to orally present his or her qualifications to the SC.

b. After (a) is completed, the Secretary of the SC shall distribute written election

ballots for both chair and vice chair. The members shall mark their selection on the ballot and provide the ballot back to the Secretary. Any SC member participating by phone shall submit his or her selections to the Secretary via email. The Chair and Vice Chair have the right to vote in both of the elections for chair and vice chair.

1 This approach was used in 2015 for election of chair and vice chair.

5. After all written and email ballots are collected by the Secretary, the Secretary and members of the nominating committee shall leave the room and together count the ballots. After the Secretary and nominating committee members agree to the vote count, they shall re-enter the room and announce the vote count totals. If for any reason a majority of votes was not received by a nominee for chair or vice chair, the nominee with the lowest vote count shall be dropped from the ballot and a second ballot shall be produced and a second election conducted, using the same process as used for the first ballot. This process of eliminating the lowest vote count from the nomination list shall be used until a majority vote is obtained for chair and vice chair, as needed. (Note: the intention of the election process is to allow for confidentiality of the voters, while providing the transparency of the final vote count. Thus, the Secretary of the SC and the nominating committee shall not disclose any names of who voted for who (which may have been ascertained from email ballots or otherwise) during or after the election.

6. The term, duties, and responsibilities of the elected chair and vice chair start on January

1, 2018 and end on December 31, 2019.

Background The SC Charter states in Section 5 (Officers) that: 1. Selection. Prior to the annual election of representatives to the Committee in odd

numbered years, the Committee members shall select a chair and vice chair from among their membership by majority vote. The newly elected chair and vice chair cannot represent the same industry segment. A nominating committee shall solicit nominations for chair and vice chair no less than 30 days prior to the election. The nominating committee shall consult with the chair of the NERC Board of Trustees’ Standards Oversight and Technology Committee on the nominations received.

No less than ten days before the election, the nominating committee shall provide to the Committee members the qualifications of the chair and vice chair nominees. At the time of the election, the Committee can accept nominations from the floor. Following the election, the successful candidates shall be presented to the NERC Board of Trustees for approval. The chair and vice chair, upon assuming such positions, shall cease to act as representatives of the industry segments that elected them and shall thereafter be responsible for acting in the best interests of the members as a whole.

2. Terms. The term of office for the Committee chair and vice chair is two years without

limit on the number of terms an officer may serve. A member of NERC staff serves as the Committee’s non-voting secretary.

Agenda Item 2c Standards Committee July 19, 2017

Project Management and Oversight Subcommittee

Vice Chair Selection Action Endorse the selection of Mike Brytowski of Great River Energy as vice chair of the Project Management and Oversight Subcommittee (PMOS) to complete the current term and a new two-year term starting December 2017. Background Mr. Brytowski has been an active member of PMOS for over one year. PMOS selected Mr. Brytowski to be its vice chair as set forth in the action item. With this action he will fill the remainder of the previous vice chair’s term.

Agenda Item 2d Standards Committee July 19, 2017

Regional Reliability Standard VAR-501-WECC-3 Errata

Action Approve corrections to Regional Reliability Standard VAR-501-WECC-3 Requirement R1 Severe Violation Severity Level (VSL) and Guideline and Technical Basis section to match language in requirement. Background The Federal Energy Regulatory Commission (FERC) approved VAR-501-WECC-3, the associated implementation plan and Violation Risk Factors (VRFs) and VSLs, and the retirement of VAR-501-WECC-2 in a letter order issued on April 28, 2017 in Docket No. RD17-5-000. The standard became effective on July 1, 2017 in the Western Electricity Coordinating Council (WECC) region. The WECC Reliability Standards Development Procedures govern development of WECC Regional Reliability Standards. These procedures state that any non-substantive changes, such as errata, shall be handled in accordance with the NERC Standard Processes Manual (SPM). The proposed change is an errata, so it should follow Section 12.0: Process for Correcting Errata of the SPM. Under Section 12.0 of the SPM, the Standards Committee approves errata by agreeing that the correction of the error does not change the scope or intent of the associated Reliability Standard and has no material impact on the end users of the Reliability Standard. The VAR-501-WECC-3 Requirement R1 VSL and Guidelines and Technical Basis erroneously include a functional entity. Requirement R1 of VAR-501-WECC-3 requires a Generator Owner to provide its Transmission Operator certain Generator Owner’s Operating Procedures. However, the Severe VSL for Requirement R1 states that the Generator Owner should give the Operating Procedures to the Transmission Planner. The correct functional entity in the Severe VSL should be Transmission Operator, as stated in the requirement. Similarly, the Guidelines and Technical Basis section for Requirement R1 should be revised to include the Transmission Operator instead of the Transmission Planner, to match the language in Requirement R1. NERC requests that the Standards Committee agree that these revisions do not change the scope or intent of VAR-501-WECC-3 nor do they have a material impact on the end users of VAR-501-WECC-3. Rather, these revisions correct an error in the VSLs and Guidelines and Technical Basis.

VAR-501-WECC-3.1 – Power System Stabilizer

Page 1 of 11

A. Introduction 1. Title: Power System Stabilizer (PSS)

2. Number: VAR-501-WECC-3.1

3. Purpose: To ensure the Western Interconnection is operated in a coordinated manner under normal and abnormal conditions by establishing the performance criteria for WECC power system stabilizers.

4. Applicability:

4.1 Generator Operator

4.2 Generator Owner

5. Facilities: This standard applies to synchronous generators, connected to the Bulk Electric System, that meet the definition of Commercial Operation.

6. Effective Date: The first day of the first quarter following regulatory approval, except for Requirement R3.

For units placed in first-time service after regulatory approval, Requirement R3 is effective the first day of the first quarter following final regulatory approval.

For units placed in service prior to final regulatory approval, Requirement R3 is effective the first day of the first quarter that is five years after regulatory approval.

B. Requirements and Measures

R1. Each Generator Owner shall provide to its Transmission Operator, the Generator Owner’s written Operating Procedure or other document(s) describing those known circumstances during which the Generator Owner’s PSS will not be providing an active signal to the Automatic Voltage Regulator (AVR), within 180 days of any of the following events: [Violation Risk Factor: Low] [Time Horizon: Planning Horizon]

• The effective date of this standard; • The PSS’s Commercial Operation date; or • Any changes to the PSS operating specifications.

M1. Each Generator Owner will have documented evidence that it provided to its Transmission Operator, within the time allotted as described in the procedures required under Requirement R1, written Operating Procedures or other document(s) describing those known circumstances during which the Generator Owner’s PSS will not be providing an active signal to the AVR.

For auditing purposes, because Requirement R1 conditions are intended to be unchanged unless the Transmission Operator is otherwise notified, the Generator Owner only needs to provide the documentation to the Transmission Operator one time, or whenever the operating specifications change.

Agenda Item 2d(i) Standards Committee July 19, 2017


Page 2 of 11

For auditing purposes, if a PSS is in service but is not providing an active signal to the AVR as described in Requirement R1, the disabled period does not count against the Requirement R2 mandate to be in service except as otherwise allowed.

R2. Each Generator Operator shall have its PSS in service while synchronized, except during any of the following: [Violation Risk Factor: Medium] [Time Horizon: Operating Assessment]

• Component failure

• Testing of a Bulk Electric System Element affecting or affected by the PSS

• Maintenance

• As agreed upon by the Generator Operator and the Transmission Operator

A PSS that is out of service for less than 30 minutes does not create a violation of this Requirement, regardless of cause.

M2. Each Generator Operator will have documentation of each claimed exception specified in Requirement R2. Documentation may include, but is not limited to:

• A written explanation covering the bulleted exception that describes the circumstances of the exception as allowed in Requirement R2.

• Documented evidence that the Generator Operator and the Transmission Operator agreed the PSS would not be operating during a specified set of circumstances, where the exception is claimed under the last bullet of Requirement R2.

For auditing purposes, the presumption is that the PSS was in service unless otherwise exempted in Requirement R2. Evidence need only be provided to prove the circumstances during which the PSS was not in service for periods in excess of 30 minutes.

R3. Each Generator Owner shall tune its PSS to meet the following inter-area mode criteria, except as specified in Requirement R3, Part 3.5 below: [Violation Risk Factor: Medium] [Time Horizon: Operating Assessment]

3.1. PSS shall be set to provide the measured, simulated, or calculated compensated Vt/Vref frequency response of the excitation system and synchronous machine such that the phase angle will not exceed ± 30 degrees through the frequency range from 0.2 Hertz to the lesser of 1.0 Hertz or the highest frequency at which the phase of the Vt/Vref frequency response does not exceed 90 degrees.

3.2. PSS output limits shall be set to provide at least ±5% of the synchronous machine’s nominal terminal voltage.

3.3. PSS gain shall be set to between 1/3 and 1/2 of maximum practical gain.

3.4. PSS washout time constant shall be no greater than 30 seconds.


Page 3 of 11

3.5. Units that have an excitation system or PSS that is incapable of meeting the tuning requirements of Requirement R3 are exempt from Requirement R3 until the voltage regulator is either replaced or retrofitted such that the PSS becomes capable of meeting the tuning requirements.

M3. Each Generator Owner will have documented evidence that its PSS was tuned to meet the specifications of Requirement R3.

If the exception under Requirement R3, Part 3.5, is claimed, the Generator Owner will have documented evidence describing: 1) the conditions that render the PSS incapable of meeting the tuning requirements, and 2) the date the voltage regulator was last replaced or retrofitted.

R4. Each Generator Owner shall install and complete start-up testing of a PSS on its generator within 180 days of either of the following events: [Violation Risk Factor: Medium] [Time Horizon: Operational Assessment]

• The Generator Owner connects a generator to the BES, after achieving Commercial Operation, and after the Effective Date of this standard.

• The Generator Owner replaces the voltage regulator on its existing excitation system, after achieving Commercial Operation for its generator that is connected to the BES, and after the Effective Date of this standard.

M4. Each Generator Owner will have evidence that it installed and completed start-up testing of a PSS on its generator within 180 days of either of the conditions described in Requirement R4, and when those conditions occur after the Effective Date of this standard.

For auditing purposes of Requirement R4, bullet one only applies to equipment on its initial (first energization) connection to the BES.

R5. Each Generator Owner shall repair or replace a PSS within 24 months of that PSS becoming incapable of meeting the tuning specifications stated in Requirement R3. [Violation Risk Factor: Medium] [Time Horizon: Operational Assessment]

M5. Each Generator Owner will have evidence that it repaired or replaced its PSS within 24 months of that PSS becoming incapable of meeting the tuning specifications of Requirement R3. Evidence may include, but is not limited to, documentation of the date the PSS became incapable of meeting the Requirement R3 tuning specifications, and the date the PSS was returned to service, demonstrating that the span of time between the two events was less than 24 months.


Page 4 of 11

C. Compliance 1. Compliance Monitoring Process

1.1 Compliance Enforcement Authority

NERC or the Regional Entity, or any entity as otherwise designated by an Applicable Governmental Authority, in their respective roles of monitoring and/or enforcing compliance with mandatory and enforceable Reliability Standards in their respective jurisdictions.

1.2 Compliance Monitoring and Assessment Processes

• Compliance Audits

• Self-Certifications

• Spot Checking

• Compliance Investigations

• Self-Reporting

• Complaints

1.3 Evidence Retention

The following evidence retention periods identify the period of time an entity is required to retain specific evidence to demonstrate compliance. For instances where the evidence retention period specified below is shorter than the time since the last audit, the Compliance Enforcement Authority may ask an entity to provide other evidence to show that it was compliant for the full time period since the last audit.

Each Generator Operator shall keep evidence for all Requirements of the document for a period of three years plus calendar current.

1.4 Additional Compliance Information

None

D. Regional Differences None


Page 5 of 11

Table of Compliance Elements

R Time Horizon

VRF Violation Severity Levels

Lower VSL Moderate VSL High VSL Severe VSL

R1 Planning Horizon

Low NA

NA NA The Generator Owner failed to provide its PSS operating specifications to the Transmission PlannerOperator as required in Requirement R1.

R2 Operations Assessment

Medium Each Generator Operator not having its PSS in service while synchronized in accordance with Requirement R2, for more than 30 minutes but less than 60 minutes.

Each Generator Operator not having its PSS in service while synchronized in accordance with Requirement R2, for more than 60 minutes but less than 120 minutes.

Each Generator Operator not having its PSS in service while synchronized in accordance with Requirement R2, for more than 120 minutes but less than 180 minutes.

Each Generator Operator not having its PSS in service while synchronized in accordance with Requirement R2, for more than 180 minutes.

R3 Operations Assessment

Medium The Generator Owner’s PSS failed to meet any of the required performances in Requirement R3, two times or fewer during

The Generator Owner’s PSS failed to meet any of the required performances in Requirement R3, three times during the audit period.

The Generator Owner’s PSS failed to meet any of the required performances in Requirement R3, four times during the audit period.

The Generator Owner’s PSS failed to meet any of the required performances in Requirement R3, five times or more during the audit


Page 6 of 11

R Time Horizon

VRF Violation Severity Levels


the audit period. period.

R4 Operational Assessment

Medium NA NA NA The Generator Owner failed to install on its generator a PSS, as required in Requirement R4.

R5 Operational Assessment

Medium NA NA NA The Generator Owner failed to repair or replace a non-operational PSS as required in Requirement R5.


Page 7 of 11

Version History

Version Date Action Change Tracking

1 April 16, 2008 Permanent Replacement Standard for VAR-STD-002b-1

1 October 28, 2008 Adopted by NERC Board of Trustees

1 April 21, 2011

FERC Order issued approving VAR- 501-WECC-1 (FERC approval effective June 27, 2011; Effective Date July 1, 2011)

2 November 13, 2014 Adopted by NERC Board of Trustees

2 March 3, 2015 FERC letter order approved VAR-501-WECC-2

3 TBDFebruary 9, 2017

TBDAdopted by NERC Board of Trustees

3 April 28, 2017 FERC letter order approved VAR-501-WECC-3

3.1 TBD TBD


Page 8 of 11

Guideline and Technical Basis PSS systems are used to minimize real power oscillations by rapidly adjusting the field of the generator to dampen the low-frequency oscillations. It is necessary for large numbers of PSS devices to be in operation in the Western Interconnection to provide the required system damping while still allowing for some of these units to be out of service whenever necessary. Mandate to Install a PSS Nothing in this Regional Reliability Standard (RSS) should be construed to require installation of a PSS solely because a PSS is not currently installed as of the Effective Date of this RRS. Rather, installation is only mandated on the occurrence of either of the triggering events described in Requirement R4, Bullet 1 or Bullet 2, after the Effective Date of the RRS. It should be noted that a PSS is neither Transmission nor generation. Requirement R1 Requirement R1 addresses normal operating conditions.

Requirement R1 recognizes that PSS systems have varying states, such as on, off, active, and non-active. As long as the PSS is operating in accordance with the documentation provided to the Transmission PlannerOperator, this is not considered a status change for purposes of this standard.

This Requirement eliminates the requirement to count hours as required in the previous version of this standard while also allowing the Generator Owner to create a unit-specific operating plan.

The intent of Requirement R1 is to provide the Transmission PlannerOperator, the PSS operating zone in which the PSS is “active” providing damping to the power system. Some PSS may be programmed to become “active” at a specified megawatt loading level and above while others may be programmed to be “active” in a particular band of megawatt loading levels and are “non-active” only when passing through the “rough zone” or some other band. A “rough zone” is a megawatt loading band in which the generator-turbine system could contribute to system instability. Requirement R2 This Requirement only applies when the PSS is out of service for a period greater than 30 minutes.

Unlike Requirement R1, Requirement R2 addresses exceptions to normal operation.


Page 9 of 11

The intent of Requirement R2 is to remove the previous requirement to log hours for PSS in service. In this standard’s previous version, the logged hours were totaled quarterly to meet the 98% in-service requirement. Instead of documenting the number of hours excluded, this Requirement simplifies the process by allowing the Generator Operator to communicate to the Transmission Operator the circumstances that render the PSS unavailable to the Transmission Operator (such as component failure, maintenance, and testing). Requirement R3 Nothing in this RSS should be construed to mandate the design criteria for the equipment used to produce the tuning output of the PSS. Rather, Requirement R3 is intended to address the design criteria for the tuning output of the PSS. Unlike the language in Requirement R5 that looks backward to address units that were once operating but are no longer capable of operating, Requirement R3 looks forward, requiring that units be tuned to the specified parameters.

The PSS transfer function should compensate the phase characteristics of the generator, exciter, and power (GEP) system transfer function so the compensated transfer function ((PSS(s) * GEP(s)) has a phase characteristic of ± 30 degrees in the frequency range.

The GEP(s) transfer function is a theoretical transfer function and its phase characteristic cannot be directly measured during field tests (only via simulation). Thus, the Requirement recognizes the practical approach of measuring the frequency response between voltage reference set point and terminal voltage (Et/Vref) and using the phase characteristic of such frequency response as being the phase characteristic of GEP(s). The phase characteristic of Et/Vref is a better approximation to the phase characteristic of GEP(s) when the frequency response Et/Vref is obtained with the generator synchronized to the grid at its minimum stable power output.

In an effort to allow for reasonable wash-out time constants, the Requirement specifies 0.2 Hz as the applicable threshold. The 0.2 Hz threshold more closely aligns with the observed oscillation frequencies.

A properly tuned PSS should provide positive damping to the local mode of oscillation, which typically has a frequency higher than 1.0 Hz.

This Requirement modifies the requirement associated with the adjustment of the PSS gain. The standard no longer defines the PSS gain in terms of gain margin but instead requires the final PSS gain to be between 1/3 (10 dB) and 1/2 (6 dB) of the maximum practical gain that could be achieved during PSS commissioning. The maximum practical gain might be associated with the excessive noise or raised higher-frequency oscillations in the closed loop response (exciter mode) or any other form if there is inadequate closed-loop performance, as determined during PSS commissioning. It is now part of Measure M3 to show the field test results that led to the determination of the maximum practical gain.


Page 10 of 11

Requirement R4 Requirement R4 requires a Generator Owner to install a PSS on new applicable units or when excitation systems are replaced or retrofitted on existing applicable units. This Requirement applies to new excitation systems and not to existing systems that do not have PSS. The Requirement also allows a reasonable amount of time for the commissioning of new PSS. Requirement R5 Unlike the language in Requirement R3 that looks forward to ensure that a unit is tuned, Requirement R5 looks backward. Specifically, the language in Requirement R5, “becoming incapable,” indicates the unit was previously capable of meeting the tuning requirements in Requirement R3, but is no longer capable. Restated, Requirement R5 addresses units that were previously working but are now no longer working.

The intent of Requirement R5 is to remove the “tiered” approach to PSS repair/replacement following a failure. A simple, streamlined approach to allow the Generator Owner sufficient time to repair or replace a broken PSS has been written. Consideration has been given for the need to procure parts or new equipment, schedule an equipment/unit outage, and install and test the repaired or replaced PSS. It is recognized that in some instances, it may require (1) replacement of an AVR, and (2) the existence of a PSS, or both the AVR and the PSS may need to be replaced to achieve a functioning system.

The 24-month time frame is sufficient to return a functional, operating PSS to service.


Page 11 of 11

* FOR INFORMATIONAL PURPOSES ONLY *

Enforcement Dates: Standard VAR-501-WECC-3 — Power System Stabilizer

United States

Standard Requirement Enforcement Date Inactive Date VAR-501-WECC-3 TBD TBD

Agenda Item 2e Standards Committee July 19, 2017

BAL-002-2 and BAL-003-1.1 SAR Drafting Teams

Action Authorize posting for solicitation of additional nominees for Standard Authorization Request (SAR) drafting team members for Project 2017-01 BAL-003-1.1 and Project 2017-06 BAL-002-2 for a 14-day period. Background At the June 14, 2017 Standards Committee (SC) meeting, two projects, Project 2017-01 BAL-003-1.1 and Project 2017-06 BAL-002-2, were authorized to post for nominations for SAR drafting team members. Based on the pool of candidates received, there is a concern the two teams will significantly overlap. Therefore, an additional nomination period is necessary to ensure the teams are representative of industry stakeholders before the project SARs are finalized.

Three-Month Outlook

Brian Murphy, SC Chair, NextEra Energy Resources, LLCSteven Noess, Director of Standards Development, NERCStandards Committee July 19, 2017

Agenda Item 3aStandards CommitteeJuly 19, 2017

RELIABILITY | ACCOUNTABILITY2

• July Project 2017-07 Standards Alignment with Registration SARs* Project 2017-08 Modifications to CIP-014-3 SAR Project 2017-06 Modifications to BAL-002-2 Project 2017-01 Modifications to BAL-003-1.1

• August None

• September None

*Solicit a SAR drafting team to consider both the Standards Alignment of Registration and MOD-032-1 SAR and develop a combined final SAR

Authorize Nomination Solicitations


• July Project 2017-03 FAC-008 Periodic Review Project 2017-04 Periodic Review of INT Standards Project 2017-05 NUC-001-3 Periodic Review

• August None

• September None

Authorize Team Appointments


• July Project 2017-07 Standards Alignment with Registration and MOD-032-1

SARs Project 2017-08 Modifications to CIP-014-3

• August None

• September None

Authorize SAR Postings


• July Project 2016-04 Modifications to PRC-025-1

• August Project 2016-02 Modifications to CIP Standards (CIP-012-1)

• September Project 2015-09 Establish and Communicate System Operating Limits (FAC-

010, FAC-011, FAC-014) Project 2015-10 Single Points of Failure (TPL-001-4)

Authorize Initial Postings


• June None

• July None

FERC Orders and NOPRs

Agenda Item 5 Standards Committee July 19, 2017

2018 Standards Committee Meeting Dates

Action Approve the formation of a small working team of Standards Committee Executive Committee members to coordinate with NERC staff in order to determine the number and locations of Standards Committee (SC) and subcommittee meetings and their respective dates. Background The working team will consist of the three Standards Committee Executive Committee at-large members, and the SC and SC subcommittee secretaries. The group will determine the date, time, and location of in-person meetings and conference calls for the 2018 calendar year, while taking into consideration NERC Board of Trustees dates, holidays, and travel costs. The group will provide a recommendation at the September 7, 2017 meeting for SC endorsement.


Project 2016-02 Modifications to CIP Standards

Action Authorize posting proposed Reliability Standard CIP-012-1, the associated Implementation Plan, Violation Risk Factors, and Violation Severity Levels for a 45-day formal comment period with parallel initial ballot and non-binding poll during the last 10 days of the comment period. Background On January 21, 2016, the Federal Energy Regulatory Commission issued Order No. 822, approving revisions to the cybersecurity Critical Infrastructure Protection (CIP) standards, and among other things, directing NERC to develop modifications to the CIP Reliability Standards to require Responsible Entities1 to implement controls to protect, at a minimum, communication links and sensitive Bulk Electric System (BES) data communicated between BES Control Centers in a manner that is appropriately tailored to address the risks posed to the BES by the assets being protected. Proposed Reliability Standard CIP-012-1 responds to that directive by requiring cybersecurity plans to mitigate the risk of unauthorized disclosure or modification of certain data while being transmitted between Control Centers. The data subject to the standard is data used for (1) Operational Planning Analysis; (2) Real-time Assessments; and (3) Real-time monitoring. Requiring Responsible Entities to develop and implement these plans will provide higher assurance of the protection of the confidentiality and integrity of data transmitted between Control Centers required for reliable operation of the BES. The Quality Review for this posting was performed June 14-27, 2017 by Ash Mayfield (Grand River Dam Authority), Jerry Freese (Northern Indiana Public Service Co.), David Revill, and Christine Hasha (standard drafting team (SDT) leadership), Shamai Elstein and Marisa Hecht (NERC Legal staff), and Tobias R. Whitney (NERC Compliance staff). The Quality Review team reviewed the documents and provided feedback to the SDT. The SDT considered the feedback, made appropriate modifications to the draft documents, and approved submitting the final documents to the Standards Committee for authorization to post.

1 The CIP Reliability Standards collectively refer to the Functional Entities to which the standards apply as “Responsible Entities.”

CIP-012-1 – Cyber Security – Control Center Communication Networks

Draft 1 of CIP-012-1 June 2017 Page 1 of 8

Standard Development Timeline

This section is maintained by the drafting team during the development of the standard and will be removed when the standard is adopted by the NERC Board of Trustees (Board). Description of Current Draft This is the first draft of the proposed standard.

Completed Actions Date

Standards Committee approved Standard Authorization Request (SAR) for posting

March 9, 2016

SAR posted for comment March 23 - April 21, 2016

SAR posted for comment June 1 – June 30, 2016

Informal comment period February 10- March 13, 2017

Anticipated Actions Date

45-day formal comment period with additional ballot TBD

10-day final ballot TBD

Board TBD

Agenda Item 6(i) Standards Committee July 19, 2017



Upon Board adoption, the rationale boxes will be moved to the Supplemental Material Section. A. Introduction

1. Title: Cyber Security – Control Center Communication Networks

2. Number: CIP-012-1

3. Purpose: To protect confidentiality and integrity of data transmitted between Control Centers required for reliable operation of the Bulk Electric System (BES).

4. Applicability:

4.1. Functional Entities: For the purpose of the requirements contained herein, the following list of functional entities will be collectively referred to as “Responsible Entities.” For requirements in this standard where a specific functional entity or subset of functional entities are the applicable entity or entities, the functional entity or entities are specified explicitly.

4.1.1. Balancing Authority

4.1.2. Generator Operator

4.1.3. Generator Owner

4.1.4. Reliability Coordinator

4.1.5. Transmission Operator

4.1.6. Transmission Owner

4.2. Exemptions: The following are exempt from Reliability Standard CIP-012-1:

4.2.1. Cyber Assets at Facilities regulated by the Canadian Nuclear Safety Commission.

4.2.2. The systems, structures, and components that are regulated by the Nuclear Regulatory Commission under a cyber security plan pursuant to 10 C.F.R. Section 73.54.

5. Effective Date: See Implementation Plan for CIP-012-1

B. Requirements and Measures

Rationale for Requirements R1 and R2: FERC Order No. 822 directed NERC to develop modifications to the CIP Reliability Standards to require Responsible Entities to implement controls to protect communication links and sensitive Bulk Electric System (BES) data communicated between BES Control Centers. Reliability Standard CIP-012-1 responds to that directive, requiring Responsible Entities to develop a plan to protect the confidentiality and integrity of sensitive data while being transmitted between Control Centers. Responsible Entities use various means to communicate information between



Control Centers. The plan for protecting these communications is required for all impact levels due to the inter-dependency of multiple impact levels.

The type of data in scope of CIP-012-1 is data used for Operational Planning Analyses, Real-time Assessments, and Real-time monitoring. The terms Operational Planning Analyses, Real-time Assessments, and Real-time used are defined in the Glossary of Terms Used in NERC Reliability Standards and used in TOP-003 and IRO-010, among other Reliability Standards.

There are differences between the plan(s) required to be developed and implemented for CIP-012-1 and the protection required in CIP-006-6 Requirement R1 Part 1.10. CIP-012-1 Requirements R1 and R2 protect the applicable data during transmission between two geographically separate Control Centers. CIP-006 Requirement R1 Part 1.10 protects nonprogrammable communication components within an Electronic Security Perimeter (ESP) but outside of a Physical Security Perimeter (PSP). The transmission of applicable data between Control Centers takes place outside of an ESP. Therefore, the protection contained in CIP-006-6 Requirement R1 Part 1.10 does not apply.

R1. The Responsible Entity shall develop one or more documented plan(s) to mitigate the

risk of the unauthorized disclosure or modification of data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring while being transmitted between Control Centers. This excludes oral communications. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]

1.1. Risk mitigation shall be accomplished by one or more of the following actions:

• Physically protecting the communication links transmitting the data;

• Logically protecting the data during transmission; or

• Using an equally effective method to mitigate the risk of unauthorized disclosure or modification of the data.

Note: If the Responsible Entity does not have a Control Center or it does not transmit the type of data specified in Requirement R1 of CIP-012-1 between two Control Centers, the requirements in CIP-012-1 would not apply to that entity.

M1. Evidence may include, but is not limited to, documented plan(s) that meet the security objective of Requirement R1.

R2. The Responsible Entity shall implement the plan(s) specified in Requirement R1, except under CIP Exceptional Circumstances.

M2. Evidence may include, but is not limited to, documentation to demonstrate implementation of methods to mitigate the risk of the unauthorized disclosure or modification of data in Requirement R1.

C. Compliance



1. Compliance Monitoring Process

1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority” means NERC or the Regional Entity, or any entity as otherwise designated by an Applicable Governmental Authority, in their respective roles of monitoring and/or enforcing compliance with mandatory and enforceable Reliability Standards in their respective jurisdictions.

1.2. Evidence Retention: The following evidence retention period(s) identify the period of time an entity is required to retain specific evidence to demonstrate compliance. For instances where the evidence retention period specified below is shorter than the time since the last audit, the Compliance Enforcement Authority may ask an entity to provide other evidence to show that it was compliant for the full-time period since the last audit.

The applicable entity shall keep data or evidence to show compliance as identified below unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation.

• The Responsible Entities shall keep data or evidence of each Requirement in this Reliability Standard for three calendar years.

• If a Responsible Entity is found non-compliant, it shall keep information related to the non-compliance until mitigation is complete and approved or for the time specified above, whichever is longer.

• The Compliance Enforcement Authority (CEA) shall keep the last audit records and all requested and submitted subsequent audit records.

1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers to the identification of the processes that will be used to evaluate data or information for the purpose of assessing performance or outcomes with the associated Reliability Standard.



Violation Severity Levels

R # Violation Severity Levels


R1. N/A

N/A

N/A The Responsible Entity failed to document one or more plan(s) that achieve the security objective to mitigate the risk of unauthorized disclosure or modification of data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring while being transmitted, excluding oral communication, between Control Centers as specified in Requirement R1.

R2. N/A N/A N/A The Responsible Entity failed to implement its plan(s) to mitigate the risk of unauthorized disclosure or modification of data used for Operational Planning Analysis, Real-time Assessments, and Real-time



monitoring while being transmitted, excluding oral communication, between Control Centers as specified in Requirement R1, except under CIP Exceptional Circumstances.

D. Regional Variances

None.

E. Associated Documents Implementation Plan.



Version History


1 TBD Respond to FERC Order No. 822 N/A

CIP-012-1 Supplemental Material


Standard Attachments None.

Implementation Plan Project 2016-02 Modifications to CIP Standards Reliability Standard CIP-012-1 Applicable Standard

• Reliability Standard CIP-012-1 - Cyber Security – Control Center Communication Networks

Requested Retirements • None

Prerequisite Standard These standard(s) or definitions must be approved before the Applicable Standard becomes effective:

• None

Applicable Entities • Balancing Authority • Generator Operator • Generator Owner • Reliability Coordinator • Transmission Operator • Transmission Owner

Effective Date Reliability Standard CIP-012-1 - Cyber Security – Control Center Communication Networks Where approval by an applicable governmental authority is required, Reliability Standard CIP-012-1 shall become effective on the first day of the first calendar quarter that is twelve (12) calendar months after the effective date of the applicable governmental authority’s order approving the standard, or as otherwise provided for by the applicable governmental authority. Where approval by an applicable governmental authority is not required, Reliability Standard CIP-012-1 shall become effective on the first day of the first calendar quarter that is twelve (12) calendar months after the date the standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that jurisdiction.

Agenda Item 6(ii) Standards Committee July 19, 2017

Violation Risk Factor and Violation Severity Level Justifications

Project 2016-02 Modifications to CIP Standards

This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity levels (VSLs) for each requirement in CIP-012-1. Each requirement is assigned a VRF and a VSL. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when developing the VRFs and VSLs for the requirements. NERC Criteria for Violation Risk Factors High Risk Requirement A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition. Medium Risk Requirement A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability, separation, or cascading failures, nor to hinder restoration to a normal condition.

Agenda Item 6(iii) Standards Committee July 19, 2017

VRF and VSL Justifications Project 2016-02 Modifications to CIP Standards | July 2017 2

Lower Risk Requirement A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric System, or the ability to effectively monitor, control, or restore the Bulk Electric System. FERC Guidelines for Violation Risk Factors Guideline (1) – Consistency with the Conclusions of the Final Blackout Report FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could severely affect the reliability of the Bulk-Power System:

• Emergency operations

• Vegetation management

• Operator personnel training

• Protection systems and their coordination

• Operating tools and backup facilities

• Reactive power and voltage control

• System modeling and data exchange

• Communication protocol and facilities

• Requirements to determine equipment ratings

• Synchronized data recorders

• Clearer criteria for operationally critical facilities

• Appropriate use of transmission loading relief.


Guideline (2) – Consistency within a Reliability Standard FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment. Guideline (3) – Consistency among Reliability Standards FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards would be treated comparably. Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level. Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability Standard.


NERC Criteria for Violation Severity Levels VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and may have only one, two, or three VSLs. VSLs should be based on NERC’s overarching criteria shown in the table below:


The performance or product measured almost meets the full intent of the requirement.

The performance or product measured meets the majority of the intent of the requirement.

The performance or product measured does not meet the majority of the intent of the requirement, but does meet some of the intent.

The performance or product measured does not substantively meet the intent of the requirement.

FERC Order of Violation Severity Levels The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard meet the FERC Guidelines for assessing VSLs: Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current Level of Compliance Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than was required when levels of non-compliance were used. Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of Penalties A violation of a “binary” type requirement must be a “Severe” VSL. Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance. Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement VSLs should not expand on what is required in the requirement.


Guideline (4) – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of Violations Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.

VRF Justifications for CIP-012-1, Requirement R1

Proposed VRF Medium

NERC VRF Discussion A VRF of Medium was assigned to this requirement. Cyber security plans enable effective implementation of the CIP standard’s requirements to mitigate the risk of the unauthorized disclosure or modification of data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring while being transmitted between Control Centers.

FERC VRF G1 Discussion

Guideline 1- Consistency with Blackout Report

N/A


Guideline 2- Consistency within a Reliability Standard

N/A


Guideline 3- Consistency among Reliability Standards

The requirement complements CIP-005-1, Requirement R1, CIP-006-6, Requirement R1, and CIP-007-6, Requirement R1 which are related to security of networks and communications components. The proposed VRF is consistent with these related requirements.


Guideline 4- Consistency with NERC Definitions of VRFs

Failure to have a cyber security plan would not, under Emergency, abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric System, or the ability to effectively monitor, control, or restore the Bulk Electric System.

FERC VRF G5 Discussion N/A



Proposed VRF Medium

Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation

VSLs for CIP-012-1, Requirement R1

Lower Moderate High Severe

N/A

N/A

N/A The Responsible Entity failed to document one or more plan(s) that achieve the security objective to mitigate the risk of the unauthorized disclosure or modification of data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring while being transmitted, excluding oral communication, between Controls Centers as specified in Requirement R1.


VSL Justifications for CIP-012-1 Requirements R1

FERC VSL G1

Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current Level of Compliance

The requirement is new. Therefore, the proposed VSL does not have the unintended consequence of lowering the level of compliance.

FERC VSL G2

Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of Penalties

Guideline 2a: The Single Violation Severity Level Assignment Category for "Binary" Requirements Is Not Consistent

Guideline 2b: Violation Severity Level Assignments that Contain Ambiguous Language

The proposed VSL is binary and is classified as severe. The VSL does not use any ambiguous terminology, thereby supporting uniformity and consistency in the determination of similar penalties for similar violations.

FERC VSL G3

Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement

The proposed VSL uses the same terminology as used in the associated requirement and is, therefore, consistent with the requirement.


FERC VSL G4

Violation Severity Level Assignment Should Be Based on A Single Violation, Not on A Cumulative Number of Violations

The VSL is based on a single violation and not cumulative violations.


Proposed VRF Medium

NERC VRF Discussion A VRF of Medium was assigned to this requirement. Implementation of required cyber security plans enable effective implementation of the CIP standard’s requirements to mitigate the risk of the unauthorized disclosure or modification of data used for Operational Planning Analysis, Real-time Assessments, and Real-time monitoring while being transmitted between Control Centers.


Guideline 1- Consistency with Blackout Report

N/A


Guideline 2- Consistency within a Reliability Standard

N/A


Guideline 3- Consistency among Reliability Standards

The requirement complements CIP-005-1, Requirement R1, CIP-006-6, Requirement R1, and CIP-007-6, Requirement R1 which are related to security of networks and communications components. The proposed VRF is consistent with these related requirements.

FERC VRF G4 Discussion Failure to properly implement the cyber security plan would not, under Emergency, abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state



Proposed VRF Medium

Guideline 4- Consistency with NERC Definitions of VRFs

or capability of the Bulk Electric System, or the ability to effectively monitor, control, or restore the Bulk Electric System.


Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation

N/A

VSLs for CIP-012-1, Requirement R2


N/A N/A N/A The Responsible Entity failed to implement its plan to mitigate the risk of the unauthorized disclosure or modification of data used for Operational, Planning Analysis, Real-time Assessments, and Real-time monitoring while being transmitted, excluding oral communication, between Controls Centers as specified in Requirement R1, except under CIP Exceptional Circumstances.


VSL Justifications for CIP-012-1 Requirement R2

FERC VSL G1


The requirement is new. Therefore, the proposed VSL does not have the unintended consequence of lowering the level of compliance.

FERC VSL G2




The proposed VSL is binary and is classified as severe. The VSL does not use any ambiguous terminology, thereby supporting uniformity and consistency in the determination of similar penalties for similar violations.

FERC VSL G3


The proposed VSL uses the same terminology as used in the associated requirement and is, therefore, consistent with the requirement.


FERC VSL G4


The VSL is based on a single violation and not cumulative violations.


Project 2016-04 Modifications to PRC-025-1

Action Authorize the initial posting of draft Reliability Standard PRC-025-2 Generator Relay Loadability, its associated Implementation Plan, and Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) Justification for a formal 45-day comment period with ballot pool formation during the first 30 days. An initial ballot of the standard and a non-binding poll of the VRFs and VSLs to be held during the last 10 days of the comment period. Background The Reliability Standard PRC-025-1 went into effect in the United States on October 1, 2014 under a phased implementation plan based on two time frames. The first time frame was provided to the Generator Owner, Transmission Owner, or Distribution Provider to apply settings to its existing load-responsive protective relays that are capable of meeting the standard while maintaining reliable fault protection. The second and extended time frame was provided to the Generator Owner, Transmission Owner, or Distribution Provider that determined its existing load-responsive protective relays require replacement or removal. The PRC-025-1 standard drafting team recognized that it may be necessary to replace a legacy load-responsive protective relay with a modern advanced-technology relay that can be set using functions such as load encroachment, or that removal of the load-responsive protective relay is the best alternative to satisfy the entity’s protection criteria and meet the requirements of PRC-025-1.

The revisions to PRC-025-1 address the issues raised in the Standards Authorization Request by:

1. Preventing instances of non-compliance for conditions where the Generator Owner may be prevented from achieving the margin specified by the standard for dispersed power-producing resources.

2. Preventing a lowering of reliability and potential non-compliance where the Generator Owner might apply a non-standard relay element application and undermine the goal of the standard.

3. Preventing a lowering of reliability where the Generator Owner might only apply part of the Table 1 application(s) thereby misapplying the loadability margins to relays for the stated application(s).

4. Preventing a lowering of dependability of protective relays directional toward the Transmission system at generating facilities that are remote to the transmission network.

5. Modifying or eliminating the use of the term “pickup setting” and other terms or phrases that relate to initial measurements and specific detection methods, and instead,

using a term or phrase that clearly aligns with the intent of the standard for relays to “not trip” based on the setting criteria in Table 1.

6. Clarifying the standard, Attachment 1, and/or Application Guidelines based on miscellaneous considerations for clarifications.

The single Requirement, Measure, and Violation Risk Factors and Violation Severity Levels remain unchanged from PRC-025-1. The proposed Implementation Plan is consistent with the original phased-in plan of 60 and 84 months. Based on the anticipated approval by industry and subsequent approval(s) by Applicable Governmental Authorities, the standard will become enforceable 12 months after the effective date where relay removal or replacement is not necessary, and 36 months after the effective date where equipment removal or replacement is necessary.

PRC‐025‐2— Generator Relay Loadability

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This section is maintained by the drafting team during the development of the standard and will be removed when the standard is adopted by the NERC Board of Trustees (Board).

Description of Current Draft The standard drafting team (PRC_025) is posting Draft 1 of PRC‐025‐2, Generator Relay Loadability for a 45‐day formal comment period and initial ballot in the last ten days of the comment period.


The Standards Committee (SC) authorized the SAR for posting September 14, 2016

Draft 1 of the Standards Authorization Request (SAR) was posted for a 30‐day formal comment period

September 16, 2016 through October 18, 2016

Draft 2 of the SAR was posted for a 15‐day informal comment period March 20, 2017 through April 3, 2017

The SC accepted the SAR and appointed the SAR drafting team as the standard drafting team (SDT)

April 19, 2017


45‐day formal comment period with initial ballot July 2017

45‐day formal comment period with additional ballot September 2017

10‐day final ballot January 2018

Board adoption February 2018

New or Modified Term(s) Used in NERC Reliability Standards This section includes all new or modified terms used in the proposed standard that will be included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory approval. Terms used in the proposed standard that are already defined and are not being modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or revised terms listed below will be presented for approval with the proposed standard. Upon Board adoption, this section will be removed.

Agenda Item 7(i)Standards CommitteeJuly 19, 2017


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Term(s): None.


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A. Introduction 1. Title: Generator Relay Loadability

2. Number: PRC‐025‐2

3. Purpose: To set load‐responsive protective relays associated with generation Facilities at a level to prevent unnecessary tripping of generators during a system disturbance for conditions that do not pose a risk of damage to the associated equipment.

4. Applicability:

4.1. Functional Entities:

4.1.1. Generator Owner that applies load‐responsive protective relays at the terminals of the Elements listed in 3.2, Facilities.

4.1.2. Transmission Owner that applies load‐responsive protective relays at the terminals of the Elements listed in 3.2, Facilities.

4.1.3. Distribution Provider that applies load‐responsive protective relays at the terminals of the Elements listed in 3.2, Facilities.

4.2. Facilities: The following Elements associated with Bulk Electric System (BES) generating units and generating plants, including those generating units and generating plants identified as Blackstart Resources in the Transmission Operator’s system restoration plan:

4.2.1. Generating unit(s).

4.2.2. Generator step‐up (i.e., GSU) transformer(s).

4.2.3. Unit auxiliary transformer(s) (UAT) that supply overall auxiliary power necessary to keep generating unit(s) online.1

4.2.4. Elements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. Elements may also supply generating plant loads.

4.2.5. Elements utilized in the aggregation of dispersed power producing resources.

5. Effective Date: See Implementation Plan

6. Background: After analysis of many of the major disturbances in the last 25 years on the North American interconnected power system, generators have been found to have

1 These transformers are variably referred to as station power, unit auxiliary transformer(s) (UAT), or station service transformer(s) used to provide overall auxiliary power to the generator station when the generator is running. Loss of these transformers will result in removing the generator from service. Refer to the PRC‐025‐2 Guidelines and Technical Basis for more detailed information concerning unit auxiliary transformers.


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tripped for conditions that did not apparently pose a direct risk to those generators and associated equipment within the time period where the tripping occurred. This tripping has often been determined to have expanded the scope and/or extended the duration of that disturbance. This was noted to be a serious issue in the August 2003 “blackout” in the northeastern North American continent.2

During the recoverable phase of a disturbance, the disturbance may exhibit a “voltage disturbance” behavior pattern, where system voltage may be widely depressed and may fluctuate. In order to support the system during this transient phase of a disturbance, this standard establishes criteria for setting load‐responsive protective relays such that individual generators may provide Reactive Power within their dynamic capability during transient time periods to help the system recover from the voltage disturbance. The premature or unnecessary tripping of generators resulting in the removal of dynamic Reactive Power exacerbates the severity of the voltage disturbance, and as a result changes the character of the system disturbance. In addition, the loss of Real Power could initiate or exacerbate a frequency disturbance.

7. Standard Only Definition: None.

B. Requirements and Measures R1. Each Generator Owner, Transmission Owner, and Distribution Provider shall apply

settings that are in accordance with PRC‐025‐2 – Attachment 1: Relay Settings, on each load‐responsive protective relay while maintaining reliable fault protection. [Violation Risk Factor: High] [Time Horizon: Long‐Term Planning]

M1. For each load‐responsive protective relay, each Generator Owner, Transmission Owner, and Distribution Provider shall have evidence (e.g., summaries of calculations, spreadsheets, simulation reports, or setting sheets) that settings were applied in accordance with PRC‐025‐2 – Attachment 1: Relay Settings.

C. Compliance 8. Compliance Monitoring Process

8.1. Compliance Enforcement Authority

As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority” means NERC or the Regional Entity in their respective roles of monitoring and enforcing compliance with the NERC Reliability Standards.

2 Interim Report: Causes of the August 14th Blackout in the United States and Canada, U.S.‐Canada Power System Outage Task Force, November 2003 (http://www.nerc.com/docs/docs/blackout/814BlackoutReport.pdf)


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8.2. Evidence Retention

The following evidence retention periods identify the period of time an entity is required to retain specific evidence to demonstrate compliance. For instances where the evidence retention period specified below is shorter than the time since the last audit, the Compliance Enforcement Authority (CEA) may ask an entity to provide other evidence to show that it was compliant for the full time period since the last audit.

The Generator Owner, Transmission Owner, and Distribution Provider shall keep data or evidence to show compliance as identified below unless directed by its CEA to retain specific evidence for a longer period of time as part of an investigation:

The Generator Owner, Transmission Owner, and Distribution Provider shall retain evidence of Requirement R1 and Measure M1 for the most recent three calendar years.

If a Generator Owner, Transmission Owner, or Distribution Provider is found non‐compliant, it shall keep information related to the non‐compliance until mitigation is complete and approved or for the time specified above, whichever is longer.

The CEA shall keep the last audit records and all requested and submitted subsequent audit records.

8.3. Compliance Monitoring and Assessment Processes

Compliance Audit

Self‐Certification

Spot Checking

Compliance Investigation

Self‐Reporting

Complaint

8.4. Additional Compliance Information

None.


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R # Time Horizon VRF



R1 Long‐Term

Planning High N/A N/A N/A

The Generator Owner, Transmission Owner, and Distribution Provider did not apply settings in accordance with PRC‐025‐2 – Attachment 1: Relay Settings, on an applied load‐responsive protective relay.

D. Regional Variances None.

E. Associated Documents NERC System Protection and Control Subcommittee, “Considerations for Power Plant and Transmission System Protection Coordination,” technical reference document, Revision 2. (Date of Publication: July 2015)

IEEE C37.102‐2006, “IEEE Guide for AC Generator Protection.” (Date of Publication: 2006)

IEEE C37.17‐2012, “IEEE Standard for Trip Systems for Low‐Voltage (1000 V and below) AC and General Purpose (1500 V and below) DC Power Circuit Breakers.” (Date of Publication: September 18, 2012)

IEEE C37.2‐2008, “IEEE Standard for Electrical Power System Device Function Numbers, Acronyms, and Contact Designations.” (Date of Publication: October 3, 2008)


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Version History


1 August 15, 2013

Adopted by NERC Board of Trustees New

1 July 17, 2014 FERC order issued approving PRC‐025‐1

2 April 19, 2017 SAR accepted by Standards Committee Revision

2 Adopted by NERC Board of Trustees

2 FERC order issued approving PRC‐025‐2


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PRC-025-2 – Attachment 1: Relay Settings

Introduction This standard does not require the Generator Owner, Transmission Owner, or Distribution Provider to use any of the protective functions listed in Table 1. Each Generator Owner, Transmission Owner, and Distribution Provider that applies load‐responsive protective relays on their respective Elements listed in 3.2, Facilities, shall use one of the following Options in Table 1, Relay Loadability Evaluation Criteria (“Table 1”), to set each load‐responsive protective relay element according to its application and relay type. The bus voltage is based on the criteria for the various applications listed in Table 1. Generators Synchronous generator relay setting criteria values are derived from the unit’s maximum gross Real Power capability, in megawatts (MW), as reported to the Transmission Planner, and the unit’s Reactive Power capability, in megavoltampere‐reactive (Mvar), is determined by calculating the MW value based on the unit’s nameplate megavoltampere (MVA) rating at rated power factor. If different seasonal capabilities are reported, the maximum capability shall be used for the purposes of this standard as a minimum requirement. The Generator Owner may base settings on a capability that is higher than what is reported to the Transmission Planner. Asynchronous generator relay setting criteria values (including inverter‐based installations) are derived from the site’s aggregate maximum complex power capability, in MVA, as reported to the Transmission Planner, including the Mvar output of any static or dynamic reactive power devices. If different seasonal capabilities are reported, the maximum capability shall be used for the purposes of this standard as a minimum requirement. The Generator Owner may base settings on a capability that is higher than what is reported to the Transmission Planner. For applications where synchronous and asynchronous generator types are combined on a generator step‐up transformer or on Elements that connect the generator step‐up (GSU) transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant (Elements may also supply generating plant loads), the setting criteria shall be determined by vector summing the setting criteria of each generator type, and using the bus voltage for the given synchronous generator application and relay type. Transformers Calculations using the GSU transformer turns ratio shall use the actual tap that is applied (i.e., in service) for GSU transformers with de‐energized tap changers (DETC). If load tap changers (LTC) are used, the calculations shall reflect the tap that results in the lowest generator bus voltage. When the criterion specifies the use of the GSU transformer’s impedance, the nameplate impedance at the nominal GSU transformer turns ratio shall be used. Applications that use more complex topology, such as generators connected to a multiple winding transformer, are not directly addressed by the criteria in Table 1. These topologies can result in complex power flows, and may require simulation to avoid overly conservative


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assumptions to simplify the calculations. Entities with these topologies should set their relays in such a way that they do not operate for the conditions being addressed in this standard. Multiple Lines Applications that use more complex topology, such as multiple lines that connect the generator step‐up (GSU) transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant (Elements may also supply generating plant loads) are not directly addressed by the criteria in Table 1. These topologies can result in complex power flows, and it may require simulation to avoid overly conservative assumptions to simplify the calculations. Entities with these topologies should set their relays in such a way that they do not operate for the conditions being addressed in this standard. Exclusions The following protection systems are excluded from the requirements of this standard:

1. Any relay elements that are in service only during start up. 2. Load‐responsive protective relay elements that are armed only when the generator is

disconnected from the system, (e.g., non‐directional overcurrent elements used in conjunction with inadvertent energization schemes, and open breaker flashover schemes).

3. Phase fault detector relay elements employed to supervise other load‐responsive phase distance elements (e.g., in order to prevent false operation in the event of a loss of potential) provided the distance element is set in accordance with the criteria outlined in the standard.

4. Protective relay elements that are only enabled when other protection elements fail (e.g., overcurrent elements that are only enabled during loss of potential conditions).

5. Protective relay elements used only for Remedial Action Schemes that are subject to one or more requirements in a NERC or Regional Reliability Standard.

6. Protection systems that detect generator overloads that are designed to coordinate with the generator short time capability by utilizing an extremely inverse characteristic set to operate no faster than 7 seconds at 218% of full load current (e.g., rated armature current), and prevent operation below 115% of full‐load current.3

7. Protection systems that detect overloads and are designed only to respond in time periods which allow an operator 15 minutes or greater to respond to overload conditions.

Table 1 Table 1 below is structured and formatted to aid the reader with identifying an option for a given load‐responsive protective relay. The first column identifies the application (e.g., synchronous or asynchronous generators, generator step‐up transformers, unit auxiliary transformers, Elements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly

3 IEEE C37.102‐2006, “Guide for AC Generator Protection,” Section 4.1.1.2.


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from a BES generating unit or generating plant). Dark blue horizontal bars, excluding the header which repeats at the top of each page, demarcate the various applications. The second column identifies the load‐responsive distance or overcurrent protective relay by IEEE device numbers (e.g., 21, 50, 51, 51V‐C, 51V‐R, or 67) according to the application in the first column. This also includes manufacture protective device trip unit designations for long‐time delay, short‐time delay, and instantaneous (e.g., L, S, and I). A light blue horizontal bar between the relay types is the demarcation between relay types for a given application. These light blue bars will contain no text, except when the same application continues on the next page of the table with a different relay type. The third column uses numeric and alphabetic options (i.e., index numbering) to identify the available options for setting load‐responsive protective relays according to the application and applied relay type. Another, shorter, light blue bar contains the word “OR,” and reveals to the reader that the relay for that application has one or more options (i.e., “ways”) to determine the bus voltage and setting criteria in the fourth and fifth column, respectively. The bus voltage column and setting criteria columns provide the criteria for determining an appropriate setting. The table is further formatted by shading groups of relays associated with asynchronous generator applications. Synchronous generator applications and the unit auxiliary transformer applications are not shaded. Also, intentional buffers were added to the table such that similar options, as possible, would be paired together on a per page basis. Note that some applications may have an additional pairing that might occur on adjacent pages.


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Table 1. Relay Loadability Evaluation Criteria

Application Relay Type Option Bus Voltage4 Setting Criteria

Synchronous generating unit(s), including Elements utilized in the aggregation of dispersed power producing resources

Phase distance relay (e.g., 21) – directional toward the Transmission system

1a

Generator bus voltage corresponding to 0.95 per unit of the high‐side nominal voltage times the turns ratio of the generator step‐up transformer

The impedance element shall be set less than the calculated impedance derived from 115% of: (1) Real Power output – 100% of the gross MW capability reported to the Transmission Planner, and (2) Reactive Power output – 150% of the MW value, derived from the generator nameplate MVA rating at rated power factor

OR

1b

Calculated generator bus voltage corresponding to 0.85 per unit nominal voltage on the high‐side terminals of the generator step‐up transformer (including the transformer turns ratio and impedance)


OR

1c

Simulated generator bus voltage coincident with the highest Reactive Power output achieved during field‐forcing in response to a 0.85 per unit nominal voltage on the high‐side terminals of the generator step‐up transformer prior to field‐forcing

The impedance element shall be set less than the calculated impedance derived from 115% of: (1) Real Power output – 100% of the gross MW capability reported to the Transmission Planner, and (2) Reactive Power output –100% of the maximum gross Mvar output during field‐forcing as determined by simulation

The same application continues on the next page with a different relay type

4 Calculations using the generator step‐up (GSU) transformer turns ratio shall use the actual tap that is applied (i.e., in service) for GSU transformers with deenergized tap changers (DETC). If load tap changers (LTC) are used, the calculations shall reflect the tap that results in the lowest generator bus voltage. When the criterion specifies the use of the GSU transformer’s impedance, the nameplate impedance at the nominal GSU turns ratio shall be used.


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Synchronous generating unit(s), including Elements utilized in the aggregation of dispersed power producing resources

Phase overcurrent relay (e.g., 50, 51, or 51V‐R – voltage‐restrained)

2a


The overcurrent element shall be set greater than 115% of the calculated current derived from: (1) Real Power output – 100% of the gross MW capability reported to the Transmission Planner, and (2) Reactive Power output – 150% of the MW value, derived from the generator nameplate MVA rating at rated power factor

OR

2b



OR

2c


The overcurrent element shall be set greater than 115% of the calculated current derived from: (1) Real Power output – 100% of the gross MW capability reported to the Transmission Planner or, and (2) Reactive Power output –100% of the maximum gross Mvar output during field‐forcing as determined by simulation

Phase time overcurrent relay (e.g., 51V‐C) – voltage controlled (Enabled to operate as a function of voltage)

3


Voltage control setting shall be set less than 75% of the calculated generator bus voltage

A different application starts on the next page


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Asynchronous generating unit(s) (including inverter‐based installations), including Elements utilized in the aggregation of dispersed power producing resources


4


The impedance element shall be set less than the calculated impedance derived from 130% of the maximum aggregate nameplate MVA output at rated power factor (including the Mvar output of any static or dynamic reactive power devices)

Phase overcurrent relay (e.g., 50, 51, or 51V‐R – voltage‐restrained)

5a


The overcurrent element shall be set greater than 130% of the calculated current derived from the maximum aggregate nameplate MVA output at rated power factor (including the Mvar output of any static or dynamic reactive power devices)

OR

5b


The overcurrent element shall not infringe upon the resource capability (including the Mvar output of the resource and any static or dynamic reactive power devices) with worst case documented tolerances applied between the maximum resource capability and the overcurrent element (see Figure A).


6





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Generator step‐up transformer(s) connected to synchronous generators

Phase distance relay (e.g., 21) – directional toward the Transmission system – installed on generator‐side of the GSU transformer5

7a


The impedance element shall be set less than the calculated impedance derived from 115% of: (1) Real Power output – 100% of the aggregate generation gross MW reported to the Transmission Planner, and (2) Reactive Power output – 150% of the aggregate generation MW value, derived from the generator nameplate MVA rating at rated power factor

OR

7b



OR

7c


The impedance element shall be set less than the calculated impedance derived from 115% of: (1) Real Power output – 100% of the aggregate generation gross MW reported to the Transmission Planner, and (2) Reactive Power output –100% of the aggregate generation maximum gross Mvar output during field‐forcing as determined by simulation


5 If the relay is installed on the high‐side of the GSU transformer use Option 14.


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Phase overcurrent relay (e.g., 50 or 51) – installed on generator‐side of the GSU transformer6

8a


The overcurrent element shall be set greater than 115% of the calculated current derived from: (1) Real Power output – 100% of the aggregate generation gross MW reported to the Transmission Planner, and (2) Reactive Power output – 150% of the aggregate generation MW value, derived from the generator nameplate MVA rating at rated power factor

OR

8b



OR

8c


The overcurrent element shall be set greater than 115% of the calculated current derived from: (1) Real Power output – 100% of the aggregate generation gross MW reported to the Transmission Planner, and (2) Reactive Power output –100% of the aggregate generation maximum gross Mvar output during field‐forcing as determined by simulation




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Phase directional overcurrent relay (e.g., 67) – directional toward the Transmission system – installed on generator‐side of the GSU transformer7

9a



OR

9b



OR

9c






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Generator step‐up transformer(s) connected to asynchronous generators only (including inverter‐based installations)

Phase distance relay (e.g., 21) – directional toward the Transmission system – installed on generator‐side of the GSU transformer8

10



Phase overcurrent relay (e.g., 50 or 51) – installed on generator‐side of the GSU transformer9

11

Generator bus voltage corresponding to 1.0 per unit of the high‐side nominal voltage times the turns ratio of the generator step‐up transformer for overcurrent relays installed on the low‐side


Phase directional overcurrent relay (e.g., 67) – directional toward the Transmission system – installed on generator‐side of the GSU transformer10

12




8 If the relay is installed on the high‐side of the GSU transformer use Option 17. 9 If the relay is installed on the high‐side of the GSU transformer use Option 18. 10 If the relay is installed on the high‐side of the GSU transformer use Option 19.


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Unit auxiliary transformer(s) (UAT)

Phase overcurrent relay (e.g., 50 or 51) applied at the high‐side terminals of the UAT, for which operation of the relay will cause the associated generator to trip.

13a 1.0 per unit of the winding nominal voltage of the unit auxiliary transformer

The overcurrent element shall be set greater than 150% of the calculated current derived from the unit auxiliary transformer maximum nameplate MVA rating

OR

13b Unit auxiliary transformer bus voltage corresponding to the measured current

The overcurrent element shall be set greater than 150% of the unit auxiliary transformer measured current at the generator maximum gross MW capability reported to the Transmission Planner

Elements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant (Elements may also supply generating plant loads) – connected to synchronous generators

Phase distance relay (e.g., 21) – directional toward the Transmission system installed on the high‐side of the GSU transformer and on the remote end of line11

14a 0.85 per unit of the line nominal voltage at the relay location


OR

14b

Simulated line voltage coincident with the highest Reactive Power output achieved during field‐forcing in response to a 0.85 per unit of the line nominal voltage at the remote end of the line prior to field‐forcing



11 If the relay is installed on the generator‐side of the GSU transformer use Option 7.


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Elements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant (Elements may also supply generating plant loads) – connected to synchronous generators

Phase instantaneous overcurrent supervisory element (e.g., 50) – associated with current‐based, communication‐assisted schemes where the scheme is capable of tripping for loss of communications installed on the high‐side of the GSU transformer and remote end of the line and/or phase time overcurrent relay (e.g., 51) – installed on the high‐side of the GSU transformer and remote end of the line12



OR

15b






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Elements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant (Elements may also supply generating plant load.) –connected to synchronous generators

Phase directional instantaneous overcurrent supervisory element (e.g., 67) – associated with current‐based, communication‐assisted schemes where the scheme is capable of tripping for loss of communications directional toward the Transmission system installed on the high‐side of the GSU transformer and remote end of the line and/or phase directional time overcurrent relay (e.g., 67) – directional toward the Transmission system installed on the high‐side of the GSU transformer and remote end of the line13



OR

16b



A different application starts on the next page 13 If the relay is installed on the generator‐side of the GSU transformer use Option 9.


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Elements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant (Elements may also supply generating plant loads) –connected to asynchronous generators only (including inverter‐based installations)

Phase distance relay (e.g., 21) – directional toward the Transmission system– installed on the high‐side of the GSU transformer and on the remote end of line14

17 1.0 per unit of the line nominal voltage at the relay location





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Elements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant (Elements may also supply generating plant loads) – connected to asynchronous generators only (including inverter‐based installations)

Phase instantaneous overcurrent supervisory element (e.g., 50) – associated with current‐based, communication‐assisted schemes where the scheme is capable of tripping for loss of communications installed on the high‐side of the GSU transformer and on the remote end of the line and/or Phase time overcurrent relay (e.g., 51) – installed on the high‐side of the GSU transformer and on the remote end of the line15






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Elements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant (Elements may also supply generating plant loads) –connected to asynchronous generators only (including inverter‐based installations)

Phase directional instantaneous overcurrent supervisory element (e.g., 67) – associated with current‐based, communication‐assisted schemes where the scheme is capable of tripping for loss of communications directional toward the Transmission system installed on the high‐side of the GSU transformer and on the remote end of the line and/or Phase directional time overcurrent relay (e.g., 67) – installed on the high‐side of the GSU transformer and on the remote end of the line16



End of Table 1



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Figure A. This figure is for demonstration of Option 5b and does not mandate a specific type of protective curve or device manufacturer.

PRC‐025‐2 — Application Guidelines

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PRC-025-2 Guidelines and Technical Basis

Introduction The document, “Considerations for Power Plant and Transmission System Protection Coordination,” published by the NERC System Protection and Control Subcommittee (SPCS) provides extensive general discussion about the protective functions and generator performance addressed within this standard. This document was last revised in July 2015.17 The basis for the standard’s loadability criteria for relays applied at the generator terminals or low‐side of the generator step‐up (GSU) transformer is the dynamic generating unit loading values observed during the August 14, 2003 blackout, other subsequent system events, and simulations of generating unit response to similar system conditions. The Reactive Power output observed during field‐forcing in these events and simulations approaches a value equal to 150 percent of the Real Power (MW) capability of the generating unit when the generator is operating at its Real Power capability. In the SPCS technical reference document, two operating conditions were examined based on these events and simulations: (1) when the unit is operating at rated Real Power in MW with a level of Reactive Power output in Mvar which is equivalent to 150 percent times the rated MW value (representing some level of field‐forcing) and (2) when the unit is operating at its declared low active Real Power operating limit (e.g., 40 percent of rated Real Power) with a level of Reactive Power output in Mvar which is equivalent to 175 percent times the rated MW value (representing some additional level of field‐forcing). Both conditions noted above are evaluated with the GSU transformer high‐side voltage at 0.85 per unit. These load operating points are believed to be conservatively high levels of Reactive Power out of the generator with a 0.85 per unit high‐side voltage which was based on these observations. However, for the purposes of this standard it was determined that the second load point (40 percent) offered no additional benefit and only increased the complexity for an entity to determine how to comply with the standard. Given the conservative nature of the criteria, which may not be achievable by all generating units, an alternate method is provided to determine the Reactive Power output by simulation. Also, to account for Reactive Power losses in the GSU transformer, a reduced level of output of 120 percent times the rated MW value is provided for relays applied at the high‐side of the GSU transformer and on Elements that connect a GSU transformer to the Transmission system and are used exclusively to export energy directly from a BES generating unit or generating plant. The phrase, “while maintaining reliable fault protection” in Requirement R1, describes that the Generator Owner, Transmission Owner, and Distribution Provider is to comply with this standard while achieving its desired protection goals. Load‐responsive protective relays, as addressed within this standard, may be intended to provide a variety of backup protection functions, both within the generating unit or generating plant and on the Transmission system, and this standard is not intended to result in the loss of these protection functions. Instead, it is suggested that the 17 http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20 Gen%20Prot%20Coordination%20Technical%20Reference%20Document.pdf


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Generator Owner, Transmission Owner, and Distribution Provider consider both the requirement within this standard and its desired protection goals, and perform modifications to its protective relays or protection philosophies as necessary to achieve both. For example, if the intended protection purpose is to provide backup protection for a failed Transmission breaker, it may not be possible to achieve this purpose while complying with this standard if a simple mho relay is being used. In this case, it may be possible to meet this purpose by replacing the legacy relay with a modern advanced‐technology relay that can be set using functions such as load encroachment. It may otherwise be necessary to reconsider whether this is an appropriate method of achieving protection for the failed Transmission breaker, and whether this protection can be better provided by, for example, applying a breaker failure relay with a transfer trip system. Requirement R1 establishes that the Generator Owner, Transmission Owner, and Distribution Provider must understand the applications of Attachment 1: Relay Settings, Table 1: Relay Loadability Evaluation Criteria (“Table 1”) in determining the settings that it must apply to each of its load‐responsive protective relays to prevent an unnecessary trip of its generator during the system conditions anticipated by this standard. Applicability To achieve the reliability objective of this standard it is necessary to include all load‐responsive protective relays that are affected by increased generator output in response to system disturbances. This standard is therefore applicable to relays applied by the Generator Owner, Transmission Owner, and Distribution Provider at the terminals of the generator, GSU transformer, unit auxiliary transformer (UAT), Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant, and Elements utilized in the aggregation of dispersed power producing resources. The Generator Owner’s interconnection facility (in some cases labeled a “transmission Facility” or “generator leads”) consists of Elements between the GSU transformer and the interface with the portion of the Bulk Electric System (BES) where Transmission Owners take over the ownership. This standard does not use the industry recognized term “generator interconnection Facility” consistent with the work of Project 2010‐07 (Generator Requirements at the Transmission Interface), because the term generator interconnection Facility implies ownership by the Generator Owner. Instead, this standard refers to these Facilities as “Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant” to include these Facilities when they are also owned by the Transmission Owner or Distribution Provider. The load‐responsive protective relays in this standard for which an entity shall be in compliance is dependent on the location and the application of the protective functions. Figures 1, 2, and 3 illustrate various generator interface connections with the Transmission system.


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Figure 1 Figure 1 is a single (or set) of generators connected to the Transmission system through a radial line that is used exclusively to export energy directly from a BES generating unit or generating plant to the network. The protective relay R1 located on the high‐side of the GSU transformer breaker CB100 is generally applied to provide backup protection to the relaying located at Bus A and in some cases Bus B. Under this application, relay R1 would apply the loadability requirement in PRC‐025‐2 using an appropriate option for the application from Table 1 (e.g., Options 14 through 19) for Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. The protective relay R2 located on the incoming source breaker CB102 to the generating plant applies relaying that primarily protects the line by using line differential relaying from Bus A to B and also provides backup protection to the transmission relaying at Bus B. In this case, the relay function that provides line protection would apply the loadability requirement in PRC‐025‐2 and an appropriate option for the application from Table 1 (e.g., 15a, 15b, 16a, 16b, 18, and 19) for phase overcurrent supervisory elements (i.e., phase fault detectors) associated with current‐based, communication‐assisted schemes (i.e., pilot wire, phase comparison, and line current differential) where the scheme is capable of tripping for loss of communications. The backup protective function would apply the requirement in the PRC‐025‐2 standard using an appropriate option for the application from Table 1 (e.g., Options 14 through 19) for Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. Since Elements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant are applicable to the standard, the loadability for relays applied on these Elements as shown in the shaded area of Figure 1 (i.e., CB102 and CB103) must be considered. If relay R2 or R3 is set with an element directional toward the transmission system (e.g., Buses B, C and D) or are non‐directional, the relay would be affected by increased generator output in response to system disturbances and must meet the loadability setting criteria described in the standard. If relay R2 or R3 is set with an element directional toward the generator (e.g., Bus A), the relay would not be affected by increased generator output in response to system disturbances; therefore, the entity would not be required to apply the loadability setting criteria described in this standard.


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Figure 1. Generation exported through a single radial line.

Figure 2 Figure 2 is an example of a single (or set) of generators connected to the Transmission system through multiple lines that are used exclusively to export energy directly from a BES generating unit or generating plant to the network. The protective relay R1 on the high‐side of the GSU transformer breaker CB100 is generally applied to provide backup protection to the Transmission relaying located at Bus A and in some cases Bus B. Under this application, relay R1 would apply the loadability requirement in PRC‐025‐2 using an appropriate option for the application from Table 1 (e.g., Options 14 through 19) for Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. The protective relays R2 and R3 located on the incoming source breakers CB102 and CB103 to the generating plant applies relaying that primarily protects the line from Bus A to B and also provides backup protection to the transmission relaying at Bus B. In this case, the relay function that provides line protection would apply the loadability requirement in PRC‐025‐2 and an appropriate option for the application from Table 1 (e.g., Options 15a, 15b, 16a, 16b, 18, and 19) for phase overcurrent supervisory elements (i.e., phase fault detectors) associated with current‐


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based, communication‐assisted schemes (i.e., pilot wire, phase comparison, and line current differential) where the scheme is capable of tripping for loss of communications. The backup protective function would apply the requirement in the PRC‐025‐2 standard using an appropriate option for the application from Table 1 (e.g., Options 14 through 19) for Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. Since Elements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant are applicable to the standard, the loadability for relays applied on these Elements as shown in the shaded area of Figure 2 (i.e., CB102, CB103, CB104, and CB105) must be considered. If relay R2, R3, R4, or R5 is set with an element directional toward the transmission system (e.g., Buses B, C and D) or are non‐directional, the relay would be affected by increased generator output in response to system disturbances and must meet the loadability setting criteria described in the standard. If relay R2, R3, R4, or R5 is set with an element directional toward the generator (e.g., Bus A), the relay would not be affected by increased generator output in response to system disturbances; therefore, the entity would not be required to apply the loadability setting criteria described in this standard.

Figure 2. Generation exported through multiple radial lines.


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Figure 3 Figure 3 is example a single (or set) of generators exporting power dispersed through multiple lines to the Transmission system through a network. The protective relay R1 on the high‐side of the GSU transformer breaker CB100 is generally applied to provide backup protection to the Transmission relaying located at Bus A and in some cases Bus C or Bus D. Under this application, relay R1 would apply the applicable loadability requirement in PRC‐025‐2 using an appropriate option for the application from Table 1 (e.g., Options 14 through 19) for Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. Since the lines from Bus A to Bus C and from Bus A to Bus D are part of the transmission network, these lines would not be considered as Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. Therefore, the applicable responsible entity would be responsible for the load‐responsive protective relays R2 and R3 under the PRC‐023 standard. The applicable responsible entity’s loadability relays R4 and R5 located on the breakers CB104 and CB105 at Bus C and D are also subject to the requirements of the PRC‐023 standard.

Relays subject to PRC-025

CB101

CB100

GSU

UATBus A

CB102

Bus D

Bus C

R2

R1

CB103

R3

CB104

R4

R5

CB105

Figure 3. Generation exported through a network.


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Elements utilized in the aggregation of dispersed power producing resources (in some cases referred to as a “collector system”) consist of the Elements between individual generating units and the common point of interconnection to the Transmission system. This standard is also applicable to the UATs that supply station service power to support the on‐line operation of generating units or generating plants. These transformers are variably referred to as station power, unit auxiliary transformer(s), or station service transformer(s) used to provide overall auxiliary power to the generator station when the generator is running. Inclusion of these transformers satisfies a directive in FERC Order No. 733, paragraph 104, which directs NERC to include in this standard a loadability requirement for relays used for overload protection of the UAT(s) that supply normal station service for a generating unit. Synchronous Generator Performance When a synchronous generator experiences a depressed voltage, the generator will respond by increasing its Reactive Power output to support the generator terminal voltage. This operating condition, known as “field‐forcing,” results in the Reactive Power output exceeding the steady‐state capability of the generator and may result in operation of generation system load‐responsive protective relays if they are not set to consider this operating condition. The ability of the generating unit to withstand the increased Reactive Power output during field‐forcing is limited by the field winding thermal withstand capability. The excitation limiter will respond to begin reducing the level of field‐forcing in as little as one second, but may take much longer, depending on the level of field‐forcing given the characteristics and application of the excitation system. Since this time may be longer than the time‐delay of the generator load‐responsive protective relay, it is important to evaluate the loadability to prevent its operation for this condition. The generator bus voltage during field‐forcing will be higher than the high‐side voltage due to the voltage drop across the GSU transformer. When the relay voltage is supplied from the generator bus, it is necessary to assess loadability using the generator bus voltage. The criteria established within Table 1 are based on 0.85 per unit of the line nominal voltage. This voltage was widely observed during the events of August 14, 2003, and was determined during the analysis of the events to represent a condition from which the System may have recovered, had other undesired behavior not occurred. The dynamic load levels specified in Table 1 under column “Setting Criteria” are representative of the maximum expected apparent power during field‐forcing with the Transmission system voltage at 0.85 per unit, for example, at the high‐side of the GSU transformer. These values are based on records from the events leading to the August 14, 2003 blackout, other subsequent System events, and simulations of generating unit responses to similar conditions. Based on these observations, the specified criteria represent conservative but achievable levels of Reactive Power output of the generator with a 0.85 per unit high‐side voltage at the point of interconnection.


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The dynamic load levels were validated by simulating the response of synchronous generating units to depressed Transmission system voltages for 67 different generating units. The generating units selected for the simulations represented a broad range of generating unit and excitation system characteristics as well as a range of Transmission system interconnection characteristics. The simulations confirmed, for units operating at or near the maximum Real Power output, that it is possible to achieve a Reactive Power output of 1.5 times the rated Real Power output when the Transmission system voltage is depressed to 0.85 per unit. While the simulations demonstrated that all generating units may not be capable of this level of Reactive Power output, the simulations confirmed that approximately 20 percent of the units modeled in the simulations could achieve these levels. On the basis of these levels, Table 1, Options 1a (i.e., 0.95 per unit) and 1b (i.e., 0.85 per unit), for example, are based on relatively simple, but conservative calculations of the high‐side nominal voltage. In recognition that not all units are capable of achieving this level of output Option 1c (i.e., simulation) was developed to allow the Generator Owner, Transmission Owner, or Distribution Provider to simulate the output of a generating unit when the simple calculation is not adequate to achieve the desired protective relay setting. Dispersed Generation This standard is applicable to dispersed generation such as wind farms and solar arrays. The intent of this standard is to ensure the aggregate facility as defined above will remain on‐line during a system disturbance; therefore, all output load‐responsive protective relays associated with the facility are included in PRC‐025. Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed primarily for aggregating capacity, connected at a common point at a voltage of 100 kV or above are included in PRC‐025‐2. Load‐responsive protective relays that are applied on Elements that connect these individual generating units through the point of interconnection with the Transmission system are within the scope of PRC‐025‐2. For example, feeder overcurrent relays and feeder step‐up transformer overcurrent relays (see Figure 5) are included because these relays are challenged by generator loadability. In the case of solar arrays where there are multiple voltages utilized in converting the solar panel DC output to a 60Hz AC waveform, the “terminal” is defined at the 60Hz AC output of the inverter‐solar panel combination. Asynchronous Generator Performance Asynchronous generators will not respond to a disturbance with the same magnitude of apparent power that a synchronous generator will respond. Asynchronous generators, though, will support the system during a disturbance. Inverter‐based generators will provide Real Power and Reactive Power (depending on the installed capability and regional grid code requirements) and may even provide a faster Reactive Power response than a synchronous generator. The magnitude of this response may slightly exceed the steady‐state capability of the inverter but only for a short duration before limiter functions will activate. Although induction generators will not inherently supply Reactive Power, induction generator installations may include static and/or dynamic


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reactive devices, depending on regional grid code requirements. These devices also may provide Real Power during a voltage disturbance. Thus, tripping asynchronous generators may exacerbate a disturbance. Inverters, including wind turbines (i.e., Types 3 and 4) and photovoltaic solar, are commonly available with 0.90 power factor capability. This calculates to an apparent power magnitude of 1.11 per unit of rated MW. Similarly, induction generator installations, including Type 1 and Type 2 wind turbines, often include static and/or dynamic reactive devices to meet grid code requirements and may have apparent power output similar to inverter‐based installations; therefore, it is appropriate to use the criteria established in the Table 1 (i.e., Options 4, 5, 6, 10, 11, 12, 17, 18, and 19) for asynchronous generator installations. Synchronous Generator Simulation Criteria The Generator Owner, Transmission Owner, or Distribution Provider who elects a simulation option to determine the synchronous generator performance on which to base relay settings may simulate the response of a generator by lowering the Transmission system voltage at the remote end of the line or at the high‐side of the GSU transformer (as prescribed by the Table 1 criteria). This can be simulated by means such as modeling the connection of a shunt reactor at the remote end of the line or at the GSU transformer high‐side to lower the voltage to 0.85 per unit prior to field‐forcing. The resulting step change in voltage is similar to the sudden voltage depression observed in parts of the Transmission system on August 14, 2003. The initial condition for the simulation should represent the generator at 100 percent of the maximum gross Real Power capability in MW as reported to the Transmission Planner. The simulation is used to determine the Reactive Power and voltage to be used to calculate relay setting limits. The Reactive Power value obtained by simulation is the highest simulated level of Reactive Power achieved during field‐forcing. The voltage value obtained by simulation is the simulated voltage coincident with the highest Reactive Power achieved during field‐forcing. These values of Reactive Power and voltage correspond to the minimum apparent impedance and maximum current observed during field‐forcing. Phase Distance Relay – Directional Toward Transmission System (e.g., 21) Generator phase distance relays that are directional toward the Transmission system, whether applied for the purpose of primary or backup GSU transformer protection, external system backup protection, or both, were noted during analysis of the August 14, 2003 disturbance event to have unnecessarily or prematurely tripped a number of generating units or generating plants, which contributed to the scope of that disturbance. Specifically, eight generators are known to have been tripped by this protection function. These options establish criteria for phase distance relays that are directional toward the Transmission system to help assure that generators, to the degree possible, will provide System support during disturbances in an effort to minimize the scope of those disturbances.


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The phase distance relay that is directional toward the Transmission system measures impedance derived from the quotient of generator terminal voltage divided by generator stator current. Section 4.6.1.1 of IEEE C37.102‐2006, “Guide for AC Generator Protection,” describes the purpose of this protection as follows (emphasis added):

“The distance relay applied for this function is intended to isolate the generator from the power system for a fault that is not cleared by the transmission line breakers. In some cases this relay is set with a very long reach. A condition that causes the generator voltage regulator to boost generator excitation for a sustained period may result in the system apparent impedance, as monitored at the generator terminals, to fall within the operating characteristics of the distance relay. Generally, a distance relay setting of 150% to 200% of the generator MVA rating at its rated power factor has been shown to provide good coordination for stable swings, system faults involving in‐feed, and normal loading conditions. However, this setting may also result in failure of the relay to operate for some line faults where the line relays fail to clear. It is recommended that the setting of these relays be evaluated between the generator protection engineers and the system protection engineers to optimize coordination while still protecting the turbine generator. Stability studies may be needed to help determine a set point to optimize protection and coordination. Modern excitation control systems include overexcitation limiting and protection devices to protect the generator field, but the time delay before they reduce excitation is several seconds. In distance relay applications for which the voltage regulator action could cause an incorrect trip, consideration should be given to reducing the reach of the relay and/or coordinating the tripping time delay with the time delays of the protective devices in the voltage regulator. Digital multifunction relays equipped with load encroachment binders [sic] can prevent misoperation for these conditions. Within its operating zone, the tripping time for this relay must coordinate with the longest time delay for the phase distance relays on the transmission lines connected to the generating substation bus. With the advent of multifunction generator protection relays, it is becoming more common to use two‐phase distance zones. In this case, the second zone would be set as previously described. When two zones are applied for backup protection, the first zone is typically set to see the substation bus (120% of the GSU transformer). This setting should be checked for coordination with the zone‐1 element on the shortest line off of the bus. The normal zone‐2 time‐delay criteria would be used to set the


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delay for this element. Alternatively, zone‐1 can be used to provide high‐speed protection for phase faults, in addition to the normal differential protection, in the generator and iso‐phase bus with partial coverage of the GSU transformer. For this application, the element would typically be set to 50% of the transformer impedance with little or no intentional time delay. It should be noted that it is possible that this element can operate on an out‐of‐step power swing condition and provide misleading targeting.”

If a mho phase distance relay that is directional toward the Transmission system cannot be set to maintain reliable fault protection and also meet the criteria in accordance with Table 1, there may be other methods available to do both, such as application of blinders to the existing relays, implementation of lenticular characteristic relays, application of offset mho relays, or implementation of load encroachment characteristics. Some methods are better suited to improving loadability around a specific operating point, while others improve loadability for a wider area of potential operating points in the R‐X plane. The operating point for a stressed System condition can vary due to the pre‐event system conditions, severity of the initiating event, and generator characteristics such as Reactive Power capability. For this reason, it is important to consider the potential implications of revising the shape of the relay characteristic to obtain a longer relay reach, as this practice may result in a relay characteristic that overlaps the capability of the generating unit when operating at a Real Power output level other than 100 percent of the maximum Real Power capability. Overlap of the relay characteristic and generator capability could result in tripping the generating unit for a loading condition within the generating unit capability. The examples in Appendix E of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document illustrate the potential for, and need to avoid, encroaching on the generating unit capability. Phase Instantaneous Overcurrent Relay (e.g., 50) The 50 element is a non‐directional overcurrent element that typically has no intentional time delay. The primary application is for close‐in high current faults where high speed operation is required or preferred. The instantaneous overcurrent elements are subject to the same loadability issues as the time overcurrent elements referenced in this standard. Phase Time Overcurrent Relay (e.g., 51) See Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document for a detailed discussion of this protection function. Note that the setting criteria established within the Table 1 options differs from the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Rather than establishing a uniform setting threshold of 200 percent of the generator MVA rating at rated power factor for all applications, the Table 1 setting criteria are based on the maximum expected generator Real Power output based on whether the generator is a synchronous or asynchronous unit.


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Phase Time Overcurrent Relay – Voltage-Restrained (e.g., 51V-R) Phase time overcurrent voltage‐restrained relays (e.g., 51V‐R), which change their sensitivity as a function of voltage, whether applied for the purpose of primary or backup GSU transformer protection, for external system phase backup protection, or both, were noted, during analysis of the August 14, 2003 disturbance event to have unnecessarily or prematurely tripped a number of generating units or generating plants, contributing to the scope of that disturbance. Specifically, 20 generators are known to have been tripped by voltage‐restrained and voltage‐controlled protection functions together. These protective functions are variably referred to by IEEE function numbers 51V, 51R, 51VR, 51V/R, 51V‐R, or other terms. See Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document for a detailed discussion of this protection function. Phase Time Overcurrent Relay – Voltage Controlled (e.g., 51V-C) Phase time overcurrent voltage‐controlled relays (e.g., 51V‐C), enabled as a function of voltage, are variably referred to by IEEE function numbers 51V, 51C, 51VC, 51V/C, 51V‐C, or other terms. See Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document for a detailed discussion of this protection function. Phase Directional Overcurrent Relay – Directional Toward Transmission System (e.g., 67) See Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document for a detailed discussion of the phase time overcurrent protection function. The basis for setting directional and non‐directional overcurrent relays is similar. Note that the setting criteria established within the Table 1 options differs from of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Rather than establishing a uniform setting threshold of 200 percent of the generator MVA rating at rated power factor for all applications, the Table 1 setting criteria are based on the maximum expected generator Real Power output based on whether the generator is a synchronous or asynchronous unit.


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Table 1, Options

Introduction The margins in the Table 1 options are based on guidance found in the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. The generator bus voltage during field‐forcing will be higher than the high‐side voltage due to the voltage drop across the GSU transformer. When the relay voltage is supplied from the generator bus, it is necessary to assess loadability using the generator bus voltage. Relay Connections Figures 4 and 5 below illustrate the connections for each of the Table 1 options provided in PRC‐025‐2, Attachment 1: Relay Settings, Table 1: Relay Loadability Evaluation Criteria.

Figure 4. Relay Connection for corresponding synchronous options.


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To auxiliary loads

21TGSU

5000/5

5000/5

5000/5

200/1

To 345 kV system

51 V‐R51 V‐C

UAT

Aggregated MVA3‐40 MVA @ 0.85 pf1‐5 Mvar

50/51

21 50/51

67

Options 13a and 13b

Option 10

GSU Data150 MVA346.5 kV / 22 kVX = 12.14%

Option 12

Option 11

21

50/5167

Option 17

Option 19

2000/1

300/5

300/5

5000/521

51 V‐R51 V‐C

Option 18

50/51

Aggregated Mvar15 Mvar

50/51

22 kV / 12 kV

50/51

Option 5

Option 5

5 Mvar

5000/5

51 V‐R

51 V‐C

21

Options4, 5, & 6

Options4, 5, & 6

21

Figure 5. Relay Connection for corresponding asynchronous options including inverter‐based installations.

Synchronous Generators Phase Distance Relay – Directional Toward Transmission System (e.g., 21) (Options 1a, 1b, and 1c) Table 1, Options 1a, 1b, and 1c, are provided for assessing loadability for synchronous generators applying phase distance relays that are directional toward the Transmission system. These margins are based on guidance found in Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Option 1a calculates a generator bus voltage corresponding to 0.95 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying the 0.95 per unit nominal voltage, at the high‐side terminals of the GSU transformer, by the GSU transformer turns ratio (excluding the impedance). This calculation is a straightforward way to approximate the stressed system conditions.


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Option 1b calculates the generator bus voltage corresponding to 0.85 per unit nominal voltage on the high‐side terminals of the GSU transformer. The voltage drop across the GSU transformer is calculated based on a 0.85 per unit nominal voltage at the high‐side terminals of the GSU transformer as well as the turns ratio and impedance. The actual generator bus voltage may be higher depending on the GSU transformer impedance and the actual Reactive Power achieved. This calculation is a more in‐depth and precise method for setting of the impedance element than Option 1a. Option 1c simulates the generator bus voltage coincident with the highest Reactive Power output achieved during field‐forcing. This output is in response to a 0.85 per unit nominal voltage on the high‐side terminals of the GSU transformer prior to field‐forcing. Using simulation is a more involved, more precise setting of the impedance element overall. For Options 1a and 1b, the impedance element shall be set less than the calculated impedance derived from 115 percent of both: the Real Power output of 100 percent of the maximum gross MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 150 percent of the MW value, derived from the generator nameplate MVA rating at rated power factor. For Option 1c, the impedance element shall be set less than the calculated impedance derived from 115 percent of both: the Real Power output of 100 percent of the maximum gross MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 100 percent of the maximum gross Mvar output during field‐forcing as determined by simulation. Synchronous Generators Phase Overcurrent Relay – (e.g., 50, 51, or 51V-R – Voltage Restrained) (Options 2a, 2b, and 2c) Table 1, Options 2a, 2b, and 2c, are provided for assessing loadability for synchronous generators applying phase overcurrent relays (e.g., 50 or 51) or voltage‐restrained (e.g., 51V‐R) which changes its sensitivity as a function of voltage (“voltage‐restrained”). These margins are based on guidance found in Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Option 2a calculates a generator bus voltage corresponding to 0.95 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying the 0.95 per unit nominal voltage, at the high‐side terminals of the GSU transformer, by the GSU transformer turns ratio (excluding the impedance). This calculation is a straightforward way to approximate the stressed system conditions. Option 2b calculates the generator bus voltage corresponding to 0.85 per unit nominal voltage on the high‐side terminals of the GSU transformer. The voltage drop across the GSU transformer is calculated based on a 0.85 per unit nominal voltage at the high‐side terminals of the GSU transformer as well as for the turns ratio and impedance. The actual generator bus voltage may be higher depending on the GSU transformer impedance and the actual Reactive Power achieved.


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This calculation is a more in‐depth and precise method for setting of the overcurrent element than Option 2a. Option 2c simulates the generator bus voltage coincident with the highest Reactive Power output achieved during field‐forcing. This output is in response to a 0.85 per unit nominal voltage on the high‐side terminals of the GSU transformer prior to field‐forcing. Using simulation is a more involved, more precise setting of the overcurrent element overall. For Options 2a and 2b, the overcurrent element shall be set greater than 115 percent of the calculated current derived from both: the Real Power output of 100 percent of the maximum gross MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 150 percent of the MW value, derived from the generator nameplate MVA rating at rated power factor. For Option 2c, the overcurrent element shall be set greater than the calculated current derived from 115 percent of both: the Real Power output of 100 percent of the maximum gross MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 100 percent of the maximum gross Mvar output during field‐forcing as determined by simulation. Synchronous Generators Phase Time Overcurrent Relay – Voltage Controlled (e.g., 51V-C) (Option 3) Table 1, Option 3, is provided for assessing loadability for synchronous generators applying phase time overcurrent relays which are enabled as a function of voltage (“voltage‐controlled”). These margins are based on guidance found in Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Option 3 calculates the generator bus voltage corresponding to 1.0 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying the 1.0 per unit nominal voltage, at the high‐side terminals of the GSU transformer, by the GSU transformer turns ratio (excluding the impedance). This is a simple calculation that approximates the stressed system conditions. For Option 3, the voltage control setting shall be set less than 75 percent of the calculated generator bus voltage. The voltage setting must be set such that the function (e.g., 51V‐C) will not trip under extreme emergency conditions as the time overcurrent function will be set less than generator full load current. Relays enabled as a function of voltage are indifferent as to the current setting, and this option simply requires that the relays not respond for the depressed voltage. Asynchronous Generators Phase Distance Relay – Directional Toward Transmission System (e.g., 21) (Option 4) Table 1, Option 4 is provided for assessing loadability for asynchronous generators applying phase distance relays that are directional toward the Transmission system. These margins are


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based on guidance found in Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Option 4 calculates the generator bus voltage corresponding to 1.0 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying the 1.0 per unit nominal voltage, at the high‐side terminals of the GSU transformer, by the GSU transformer turns ratio (excluding the impedance). This is a simple calculation that approximates the stressed system conditions. Since the relay voltage is supplied from the generator bus, it is necessary to assess loadability using the generator‐side voltage. Asynchronous generators do not produce as much Reactive Power as synchronous generators; the voltage drop due to Reactive Power flow through the GSU transformer is not as significant. Therefore, the generator bus voltage can be conservatively estimated by reflecting the high‐side nominal voltage to the generator‐side based on the GSU transformer’s turns ratio. For Option 4, the impedance element shall be set less than the calculated impedance derived from 130 percent of the maximum aggregate nameplate MVA output at rated power factor including the Mvar output of any static or dynamic Reactive Power devices. This is determined by summing the total MW and Mvar capability of the generation equipment behind the relay and any static or dynamic Reactive Power devices that contribute to the power flow through the relay. Asynchronous Generators Phase Overcurrent Relay – (e.g., 50, 51, or 51V-R – Voltage Restrained) (Options 5a and 5b) Table 1, Option 5a is provided for assessing loadability for asynchronous generators applying phase overcurrent relays (e.g., 50 or 51) or voltage‐restrained (e.g., 51V‐R) which changes its sensitivity as a function of voltage (“voltage‐restrained”). These margins are based on guidance found in Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Option 5a calculates the generator bus voltage corresponding to 1.0 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying the 1.0 per unit nominal voltage, at the high‐side terminals of the GSU transformer, by the GSU transformer turns ratio (excluding the impedance). This is a simple calculation that approximates the stressed system conditions. Since the relay voltage is supplied from the generator bus, it is necessary to assess loadability using the generator‐side voltage. Asynchronous generators do not produce as much Reactive Power as synchronous generators; the voltage drop due to Reactive Power flow through the GSU transformer is not as significant. Therefore, the generator bus voltage can be conservatively estimated by reflecting the high‐side nominal voltage to the generator‐side based on the GSU transformer’s turns ratio.


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For Option 5a, the overcurrent element shall be set greater than 130 percent of the calculated current derived from the maximum aggregate nameplate MVA output at rated power factor including the Mvar output of any static or dynamic Reactive Power devices. This is determined by summing the total MW and Mvar capability of the generation equipment behind the relay and any static or dynamic Reactive Power devices that contribute to the power flow through the relay. For Option 5b, the overcurrent element shall be set to exceed the maximum capability of the asynchronous resource and applicable equipment (e.g., windings, power electronics, cables, or bus). This is determined by summing the total current capability of the generation equipment behind the overcurrent element and any static or dynamic Reactive Power devices that contribute to the power flow through the overcurrent element. The overcurrent element shall be set to not infringe upon the resource capability with worst case documented tolerances applied to the setting. Figure A illustrates that the overcurrent element does not infringe upon the asynchronous resource capability. The upper hashed area of Figure A represents Exclusion 7. Asynchronous Generator Phase Time Overcurrent Relays – Voltage Controlled (e.g., 51V-C) (Option 6) Table 1, Option 6, is provided for assessing loadability for asynchronous generators applying phase time overcurrent relays which are enabled as a function of voltage (“voltage‐controlled”). These margins are based on guidance found in Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Option 6 calculates the generator bus voltage corresponding to 1.0 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying the 1.0 per unit nominal voltage, at the high‐side terminals of the GSU transformer, by the GSU transformer turns ratio (excluding the impedance). This is a simple calculation that approximates the stressed system conditions. For Option 6, the voltage control setting shall be set less than 75 percent of the calculated generator bus voltage. The voltage setting must be set such that the function (e.g., 51V‐C) will not trip under extreme emergency conditions as the time overcurrent function will be set less than generator full load current. Relays enabled as a function of voltage are indifferent as to the current setting, and this option simply requires that the relays not respond for the depressed voltage. Generator Step-up Transformer (Synchronous Generators) Phase Distance Relays – Directional Toward Transmission System (e.g., 21) (Options 7a, 7b, and 7c) The Federal Energy Regulatory Commission, in FERC Order No. 733, paragraph 104, directs that NERC address relay loadability for protective relays applied on GSU transformers. These margins are based on guidance found in Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document.


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Table 1, Options 7a, 7b, and 7c, are provided for assessing loadability of phase distance relays that are directional toward the Transmission system and connected to the generator‐side of the GSU transformer of a synchronous generator. For applications where the relay is connected on the high‐side of the GSU transformer, use Option 14. Option 7a calculates a generator bus voltage corresponding to 0.95 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying the 0.95 per unit nominal voltage, at the high‐side terminals of the GSU transformer, by the GSU transformer turns ratio (excluding the impedance). This calculation is a straightforward way to approximate the stressed system conditions. Option 7b calculates the generator bus voltage corresponding to 0.85 per unit nominal voltage on the high‐side terminals of the GSU transformer. The voltage drop across the GSU transformer is calculated based on the 0.85 per unit nominal voltage, at the high‐side terminals of the GSU transformer, as well as the turns ratio and impedance. The actual generator bus voltage may be higher depending on the GSU transformer impedance and the actual Reactive Power achieved. This calculation is a more in‐depth and precise method for setting the impedance element than Option 7a. Option 7c simulates the generator bus voltage coincident with the highest Reactive Power output achieved during field‐forcing. This output is in response to a 0.85 per unit nominal voltage on the high‐side terminals of the GSU transformer prior to field‐forcing. Using simulation is a more in‐depth and precise method for setting the impedance element than Options 7a or 7b. For Options 7a and 7b, the impedance element shall be set less than the calculated impedance derived from 115 percent of both: the Real Power output of 100 percent of the aggregate generation MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 150 percent of the aggregate generation MW value (derived from the generator nameplate MVA rating at rated power factor). For Option 7c, the impedance element shall be set less than the calculated impedance derived from 115 percent of both: the Real Power output of 100 percent of the aggregate generation MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 100 percent of the maximum gross Mvar output during field‐forcing as determined by simulation. Generator Step-up Transformer (Synchronous Generators) Phase Overcurrent Relay (e.g., 50 or 51) (Options 8a, 8b and 8c) The Federal Energy Regulatory Commission, in FERC Order No. 733, paragraph 104, directs that NERC address relay loadability for protective relays applied on GSU transformers. Note that the setting criteria established within the Table 1 options differs from Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Rather than establishing a uniform loadability threshold of 200 percent of the generator


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nameplate MVA rating at rated power factor for all applications, the setting criteria are based on the maximum expected generator output. Table 1, Options 8a, 8b, and 8c, are provided for assessing loadability of phase overcurrent relays that are connected to the generator‐side of the GSU transformer of a synchronous generator. For applications where the relay is connected on the high‐side of the GSU transformer, use Option 15. Option 8a calculates a generator bus voltage corresponding to 0.95 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying the 0.95 per unit nominal voltage, at the high‐side terminals of the GSU transformer, by the GSU transformer turns ratio (excluding the impedance). This calculation is a straightforward way to approximate the stressed system conditions. Option 8b calculates the generator bus voltage corresponding to 0.85 per unit nominal voltage on the high‐side terminals of the GSU transformer. The voltage drop across the GSU transformer is calculated based on the 0.85 per unit nominal voltage, at the high‐side terminals of the GSU transformer, as well as the turns ratio and impedance. The actual generator bus voltage may be higher depending on the GSU transformer impedance and the actual Reactive Power achieved. This calculation is a more in‐depth and precise method for setting the overcurrent element than Option 8a. Option 8c simulates the generator bus voltage coincident with the highest Reactive Power output achieved during field‐forcing. This output is in response to a 0.85 per unit nominal voltage on the high‐side terminals of the GSU transformer prior to field‐forcing. Using simulation is a more in‐depth and precise method for setting the overcurrent element than Options 8a or 8b. For Options 8a and 8b, the overcurrent element shall be set greater than 115 percent of the calculated current derived from both: the Real Power output of 100 percent of the aggregate generation MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 150 percent of the aggregate generation MW value (derived from the generator nameplate MVA rating at rated power factor). For Option 8c, the overcurrent element shall be set greater than 115 percent of the calculated current derived from both: the Real Power output of 100 percent of the aggregate generation MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 100 percent of the maximum gross Mvar output during field‐forcing as determined by simulation. Generator Step-up Transformer (Synchronous Generators) Phase Directional Overcurrent Relay – Directional Toward Transmission System (e.g., 67) (Options 9a, 9b and 9c) The Federal Energy Regulatory Commission, in FERC Order No. 733, paragraph 104, directs that NERC address relay loadability for protective relays applied on GSU transformers. Note that the


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setting criteria established within the Table 1 options differs from Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Rather than establishing a uniform loadability threshold of 200 percent of the generator nameplate MVA rating at rated power factor for all applications, the setting criteria are based on the maximum expected generator output. Table 1, Options 9a, 9b, and 9c, are provided for assessing loadability of phase directional overcurrent relays directional toward the Transmission System that are connected to the generator‐side of the GSU transformer of a synchronous generator. For applications where the relay is connected on the high‐side of the GSU transformer, use Option 16. Option 9a calculates a generator bus voltage corresponding to 0.95 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying the 0.95 per unit nominal voltage, at the high‐side terminals of the GSU transformer, by the GSU transformer turns ratio (excluding the impedance). This calculation is a straightforward way to approximate the stressed system conditions. Option 9b calculates the generator bus voltage corresponding to 0.85 per unit nominal voltage on the high‐side terminals of the GSU transformer. The voltage drop across the GSU transformer is calculated based on the 0.85 per unit nominal voltage, at the high‐side terminals of the GSU transformer, as well as the turns ratio and impedance. The actual generator bus voltage may be higher depending on the GSU transformer impedance and the actual Reactive Power achieved. This calculation is a more in‐depth and precise method for setting the overcurrent element than Option 9a. Option 9c simulates the generator bus voltage coincident with the highest Reactive Power output achieved during field‐forcing. This output is in response to a 0.85 per unit nominal voltage on the high‐side terminals of the GSU transformer prior to field‐forcing. Using simulation is a more in‐depth and precise method for setting the overcurrent element than Options 9a or 9b. For Options 9a and 9b, the overcurrent element shall be set greater than 115 percent of the calculated current derived from both: the Real Power output of 100 percent of the aggregate generation MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 150 percent of the aggregate generation MW value (derived from the generator nameplate MVA rating at rated power factor). For Option 9c, the overcurrent element shall be set greater than 115 percent of the calculated current derived from both: the Real Power output of 100 percent of the aggregate generation MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 100 percent of the maximum gross Mvar output during field‐forcing as determined by simulation.


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Generator Step-up Transformer (Asynchronous Generators) Phase Distance Relay – Directional Toward Transmission System (e.g., 21) (Option 10) The Federal Energy Regulatory Commission, in FERC Order No. 733, paragraph 104, directs that NERC address relay loadability for protective relays applied on GSU transformers. Table 1, Option 10 is provided for assessing loadability for GSU transformers applying phase distance relays that are directional toward the Transmission System that are connected to the generator‐side of the GSU transformer of an asynchronous generator. These margins are based on guidance found in Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. For applications where the relay is connected on the high‐side of the GSU transformer, use Option 17. Option 10 calculates the generator bus voltage corresponding to 1.0 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying the 1.0 per unit nominal voltage, at the high‐side terminals of the GSU transformer, by the GSU transformer turns ratio (excluding the impedance). This calculation is a straightforward way to approximate the stressed system conditions. Since the relay voltage is supplied from the generator bus, it is necessary to assess loadability using the generator‐side voltage. Asynchronous generators do not produce as much Reactive Power as synchronous generators; hence the voltage drop due to Reactive Power flow through the GSU transformer is not as significant. Therefore, the generator bus voltage can be conservatively estimated by reflecting the high‐side nominal voltage to the generator‐side based on the GSU transformer’s turns ratio. For Option 10, the impedance element shall be set less than the calculated impedance, derived from 130 percent of the maximum aggregate nameplate MVA output at rated power factor, including the Mvar output of any static or dynamic Reactive Power devices. This is determined by summing the total MW and Mvar capability of the generation equipment behind the relay and any static or dynamic Reactive Power devices that contribute to the power flow through the relay. Generator Step-up Transformer (Asynchronous Generators) Phase Overcurrent Relay (e.g., 50 or 51) (Option 11) The Federal Energy Regulatory Commission, in FERC Order No. 733, paragraph 104, directs that NERC address relay loadability for protective relays applied on GSU transformers. Note that the setting criteria established within the Table 1 options differs from Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Rather than establishing a uniform loadability threshold of 200 percent of the generator nameplate MVA rating at rated power factor for all applications, the setting criteria are based on the maximum expected generator output. Table 1, Option 11 is provided for assessing loadability of phase overcurrent relays that are connected to the generator‐side of the GSU transformer of an asynchronous generator. For


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applications where the relay is connected on the high‐side of the GSU transformer, use Option 18. Option 11 calculates the generator bus voltage corresponding to 1.0 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying the 1.0 per unit nominal voltage, at the high‐side terminals of the GSU transformer, by the GSU transformer turns ratio (excluding the impedance). This calculation is a straightforward way to approximate the stressed system conditions. Since the relay current is supplied from the generator bus, it is necessary to assess loadability using the generator‐side voltage. Asynchronous generators do not produce as much Reactive Power as synchronous generators; hence the voltage drop due to Reactive Power flow through the GSU transformer is not as significant. Therefore, the generator bus voltage can be conservatively estimated by reflecting the high‐side nominal voltage to the generator‐side based on the GSU transformer’s turns ratio. For Option 11, the overcurrent element shall be set greater than 130 percent of the calculated current derived from the maximum aggregate nameplate MVA output at rated power factor, including the Mvar output of any static or dynamic Reactive Power devices. This is determined by summing the total MW and Mvar capability of the generation equipment behind the relay and any static or dynamic Reactive Power devices that contribute to the power flow through the relay. Generator Step-up Transformer (Asynchronous Generators) Phase Directional Overcurrent Relay – Directional Toward Transmission System (e.g., 67) (Option 12) The Federal Energy Regulatory Commission, in FERC Order No. 733, paragraph 104, directs that NERC address relay loadability for protective relays applied on GSU transformers. Note that the setting criteria established within the Table 1 options differs from Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Rather than establishing a uniform loadability threshold of 200 percent of the generator nameplate MVA rating at rated power factor for all applications, the setting criteria are based on the maximum expected generator output. Table 1, Option 12 is provided for assessing loadability of phase directional overcurrent relays directional toward the Transmission System that are connected to the generator‐side of the GSU transformer of an asynchronous generator. For applications where the relay is connected on the high‐side of the GSU transformer, use Option 19. Option 12 calculates the generator bus voltage corresponding to 1.0 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying the 1.0 per unit nominal voltage, at the high‐side terminals of the GSU transformer, by the GSU transformer turns ratio (excluding the impedance). This calculation is a straightforward way to approximate the stressed system conditions.


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Since the relay current is supplied from the generator bus, it is necessary to assess loadability using the generator‐side voltage. Asynchronous generators do not produce as much Reactive Power as synchronous generators; hence the voltage drop due to Reactive Power flow through the GSU transformer is not as significant. Therefore, the generator bus voltage can be conservatively estimated by reflecting the high‐side nominal voltage to the generator‐side based on the GSU transformer’s turns ratio. For Option 12, the overcurrent element shall be set greater than 130 percent of the calculated current derived from the maximum aggregate nameplate MVA output at rated power factor, including the Mvar output of any static or dynamic Reactive Power devices. This is determined by summing the total MW and Mvar capability of the generation equipment behind the relay and any static or dynamic Reactive Power devices that contribute to the power flow through the relay. Unit Auxiliary Transformers Phase Overcurrent Relay (e.g., 50 or 51) (Options 13a and 13b) In FERC Order No. 733, paragraph 104, directs NERC to include in this standard a loadability requirement for relays used for overload protection of the UAT that supply normal station service for a generating unit. For the purposes of this standard, UATs provide the overall station power to support the unit at its maximum gross operation. Table 1, Options 13a and 13b provide two options for addressing phase overcurrent relaying applied at the high‐side of UATs. The transformer high‐side winding may be directly connected to the transmission grid or at the generator isolated phase bus (IPB) or iso‐phase bus. Phase overcurrent relays applied at the high‐side of the UAT that remove the transformer from service resulting in an immediate (e.g., via lockout or auxiliary tripping relay operation) or consequential trip of the associated generator are to be compliant with the relay setting criteria in this standard. Due to the complexity of the application of low‐side overload relays for single or multi‐winding transformers, phase overcurrent relaying applied at the low‐side of the UAT are not addressed in this standard. These relays include, but are not limited to, a relay used for arc flash protection, feeder protection relays, breaker failure, and relays whose operation may result in a generator runback. Although the UAT is not directly in the output path from the generator to the Transmission system, it is an essential component for operation of the generating unit or plant.


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Refer to the Figures 6 and 7 below for example configurations:

Unit AuxiliaryTransformers

System

System

Station Loads

Transfer Switch

GSU

G

TransformersCovered by this

standard

Figure‐6 – Auxiliary Power System (independent from generator).

Figure‐7 – Typical auxiliary power system for generation units or plants.


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The UATs supplying power to the unit or plant electrical auxiliaries are sized to accommodate the maximum expected overall UAT load demand at the highest generator output. Although the transformer nameplate MVA size normally includes capacity for future loads as well as capacity for starting of large induction motors on the original unit or plant design, the nameplate MVA capacity of the transformer may be near full load. Because of the various design and loading characteristics of UATs, two options (i.e., 13a and 13b) are provided to accommodate an entity’s protection philosophy while preventing the UAT transformer phase overcurrent relays from operating during the dynamic conditions anticipated by this standard. Options 13a and 13b are based on the transformer bus voltage corresponding to 1.0 per unit nominal voltage on the high‐side winding of the UAT. For Option 13a, the overcurrent element shall be set greater than 150 percent of the calculated current derived from the UAT maximum nameplate MVA rating. This is a simple calculation that approximates the stressed system conditions. For Option 13b, the overcurrent element shall be set greater than 150 percent of the UAT measured current at the generator maximum gross MW capability reported to the Transmission Planner. This allows for a reduced setting compared to Option 13a and the entity’s relay setting philosophy. This is a more involved calculation that approximates the stressed system conditions by allowing the entity to consider the actual load placed on the UAT based on the generator’s maximum gross MW capability reported to the Transmission Planner. The performance of the UAT loads during stressed system conditions (i.e., depressed voltages) is very difficult to determine. Rather than requiring responsible entities to determine the response of UAT loads to depressed voltage, the technical experts writing the standard elected to increase the margin to 150 percent from that used elsewhere in this standard (e.g., 115 percent) and use a generator bus voltage of 1.0 per unit. A minimum setting current based on 150 percent of maximum transformer nameplate MVA rating at 1.0 per unit generator bus voltage will provide adequate transformer protection based on IEEE C37.91 at full load conditions while providing sufficient relay loadability to prevent a trip of the UAT, and subsequent unit trip, due to increased UAT load current during stressed system voltage conditions. Even if the UAT is equipped with an automatic tap changer, the tap changer may not respond quickly enough for the conditions anticipated within this standard, and thus shall not be used to reduce this margin. Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant (Synchronous Generators) Phase Distance Relays – Directional Toward Transmission System (e.g., 21) (Options 14a and 14b) Relays applied on Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant are challenged by loading conditions similar to relays applied on generators and GSU transformers.


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These margins are based on guidance found in Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Relays applied on the high‐side of the GSU transformer respond to the same quantities as the relays connected on the Elements that connect a GSU transformer to the Transmission system (e.g., at the remote end of the line) that are used exclusively to export energy directly from a BES generating unit or generating plant, thus Option 14 is used for these relays as well. Table 1, Options 14a and 14b, establish criteria for phase distance relays directional toward the Transmission system to prevent Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant from tripping during the dynamic conditions anticipated by this standard. The stressed system conditions, anticipated by Option 14a reflects a 0.85 per unit of the line nominal voltage; therefore, establishing that the impedance value used for applying the Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant phase distance relays that are directional toward the Transmission system be calculated from the apparent power addressed within the criteria, with application of a 0.85 per unit of the line nominal voltage at the relay location. Consideration of the voltage drop across the GSU transformer is not necessary. Option 14b simulates the line voltage coincident with the highest Reactive Power output achieved during field‐forcing in response to a 0.85 per unit line nominal voltage at the remote end of the line prior to field‐forcing. Using a 0.85 per unit line nominal voltage at the remote end of the line is representative of the lowest voltage expected during a depressed voltage condition on Elements that are used exclusively to export energy directly from a BES generating unit or generating plant to the Transmission system. Using simulation is a more involved, more precise setting of the overcurrent element overall. For Option 14a, the impedance element shall be set less than the calculated impedance derived from 115 percent of both: the Real Power output of 100 percent of the aggregate generation MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 120 percent of the aggregate generation MW value, derived from the generator nameplate MVA rating at rated power factor. This Reactive Power value differs from the 150 percent multiplier used in other applications to account for the Reactive Power losses in the GSU transformer. This is a simple calculation that approximates the stressed system conditions. For Option 14b, the impedance element shall be set less than the calculated impedance derived from 115 percent of both: the Real Power output of 100 percent of the aggregate generation MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 100 percent of the maximum gross Mvar output during field‐forcing as determined by simulation. Using simulation is a more involved, more precise setting of the impedance element overall.


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Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant (Synchronous Generators) Phase Time Overcurrent Relay (e.g., 50 or 51) (Options 15a and 15b) Relays applied on Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant are challenged by loading conditions similar to relays applied on generators and GSU transformers. Note that the setting criteria established within the Table 1 options differs from Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Rather than establishing a uniform setting threshold of 200 percent of the generator nameplate MVA rating at rated power factor for all applications, the setting criteria are based on the maximum expected generator output. Relays applied on the high‐side of the GSU transformer respond to the same quantities as the relays connected on the Elements that connect a GSU transformer to the Transmission system (e.g., at the remote end of the line) that are used exclusively to export energy directly from a BES generating unit or generating plant, thus Option 15 is used for these relays as well. Table 1, Options 15a and 15b, establish criteria for phase instantaneous and/or time overcurrent relays to prevent Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant from tripping during the dynamic conditions anticipated by this standard. The stressed system conditions, anticipated by Option 15a reflects a 0.85 per unit of the line nominal voltage at the relay location; therefore, establishing that the current value used for applying the Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant phase instantaneous and/or time overcurrent relays be calculated from the apparent power addressed within the criteria, with application of a 0.85 per unit of the line nominal voltage at the relay location. Consideration of the voltage drop across the GSU transformer is not necessary. Option 15b simulates the line voltage coincident with the highest Reactive Power output achieved during field‐forcing in response to a 0.85 per unit line nominal voltage at the remote end of the line prior to field‐forcing. Using a 0.85 per unit line nominal voltage at the remote end of the line is representative of the lowest voltage expected during a depressed voltage condition on Elements that are used exclusively to export energy directly from a BES generating unit or generating plant to the Transmission system. Using simulation is a more involved, more precise setting of the overcurrent element overall. For Option 15a, the overcurrent element shall be set greater than 115 percent of the calculated current derived from both: the Real Power output of 100 percent of the aggregate generation MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 120 percent of the aggregate generation MW value, derived from the generator nameplate MVA rating at rated power factor. This Reactive Power value differs from the 150 percent multiplier used in other applications to account for the Reactive Power losses in the GSU transformer. This is a simple calculation that approximates the stressed system conditions.


Draft 1 | June 7, 2017 53 of 112

For Option 15b, the overcurrent element shall be set greater than 115 percent of the calculated current derived from both: the Real Power output of 100 percent of the aggregate generation MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 100 percent of the maximum gross Mvar output during field‐forcing as determined by simulation. Using simulation is a more involved, more precise setting of the overcurrent element overall. Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant (Synchronous Generators) Phase Directional Overcurrent Relay – Directional Toward Transmission System (e.g., 67) (Options 16a and 16b) Relays applied on Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant are challenged by loading conditions similar to relays applied on generators and GSU transformers. Note that the setting criteria established within the Table 1 options differs from Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Rather than establishing a uniform setting threshold of 200 percent of the generator nameplate MVA rating at rated power factor for all applications, the setting criteria are based on the maximum expected generator output. Relays applied on the high‐side of the GSU transformer respond to the same quantities as the relays connected on the Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant, thus Option 16 is used for these relays as well. Table 1, Options 16a and 16b, establish criteria for phase directional overcurrent relays that are directional toward the Transmission system to prevent Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant from tripping during the dynamic conditions anticipated by this standard. The stressed system conditions, anticipated by Option 16a reflects a 0.85 per unit of the line nominal voltage at the relay location; therefore, establishing that the current value used for applying the interconnection Facilities phase directional overcurrent relays be calculated from the apparent power addressed within the criteria, with application of a 0.85 per unit of the line nominal voltage at the relay location. Consideration of the voltage drop across the GSU transformer is not necessary. Option 16b simulates the line voltage coincident with the highest Reactive Power output achieved during field‐forcing in response to a 0.85 per unit line nominal voltage at the remote end of the line prior to field‐forcing. Using a 0.85 per unit line nominal voltage at the remote end of the line is representative of the lowest voltage expected during a depressed voltage condition on Elements that are used exclusively to export energy directly from a BES generating unit or generating plant to the Transmission system. Using simulation is a more involved, more precise setting of the overcurrent element overall. For Option 16a, the overcurrent element shall be set greater than 115 percent of the calculated current derived from both: the Real Power output of 100 percent of the aggregate generation MW capability reported to the Transmission Planner, and the Reactive Power output that


Draft 1 | June 7, 2017 54 of 112

equates to 120 percent of the aggregate generation MW value, derived from the generator nameplate MVA rating at rated power factor. This Reactive Power value differs from the 150 percent multiplier used in other applications to account for the Reactive Power losses in the GSU transformer. This is a simple calculation that approximates the stressed system conditions. For Option 16b, the overcurrent element shall be set greater than 115 percent of the calculated current derived from both: the Real Power output of 100 percent of the aggregate generation MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 100 percent of the maximum gross Mvar output during field‐forcing as determined by simulation. Using simulation is a more involved, more precise setting of the overcurrent element overall. Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant (Asynchronous Generators) Phase Distance Relay – Directional Toward Transmission System (e.g., 21) (Option 17) Relays applied on Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant are challenged by loading conditions similar to relays applied on generators and GSU transformers. These margins are based on guidance found in Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Table 1, Option 17 establishes criteria for phase distance relays that are directional toward the Transmission system to prevent Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant from tripping during the dynamic conditions anticipated by this standard. Option 17 applies a 1.0 per unit line nominal voltage at the relay location to calculate the impedance from the maximum aggregate nameplate MVA. For Option 17, the impedance element shall be set less than the calculated impedance derived from 130 percent of the maximum aggregate nameplate MVA output at rated power factor including the Mvar output of any static or dynamic Reactive Power devices. This is determined by summing the total MW and Mvar capability of the generation equipment behind the relay and any static or dynamic Reactive Power devices that contribute to the power flow through the relay. This is a simple calculation that approximates the stressed system conditions. Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant (Asynchronous Generators) Phase Overcurrent Relay (e.g., 50 and 51) (Option 18) Relays applied on Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant are challenged by loading conditions similar to relays applied on generators and GSU transformers. Note that the setting criteria established within the Table 1 options differs from Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical


Draft 1 | June 7, 2017 55 of 112

reference document. Rather than establishing a uniform setting threshold of 200 percent of the generator nameplate MVA rating at rated power factor for all applications, the setting criteria are based on the maximum expected generator output. Table 1, Option 18 establishes criteria for phase overcurrent relays to prevent Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant from tripping during the dynamic conditions anticipated by this standard. Option 18 applies a 1.0 per unit line nominal voltage at the location of the relay to calculate the current from the maximum aggregate nameplate MVA. For Option 18, the overcurrent element shall be set greater than 130 percent of the calculated current derived from the maximum aggregate nameplate MVA output at rated power factor including the Mvar output of any static or dynamic Reactive Power devices. This is determined by summing the total MW and Mvar capability of the generation equipment behind the relay and any static or dynamic Reactive Power devices that contribute to the power flow through the relay. This is a simple calculation that approximates the stressed system conditions. Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant (Asynchronous Generators) Phase Directional Overcurrent Relay – Directional Toward Transmission System (e.g., 67) (Option 19) Relays applied on Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant are challenged by loading conditions similar to relays applied on generators and GSU transformers. Note that the setting criteria established within the Table 1 options differs from Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Rather than establishing a uniform setting threshold of 200 percent of the generator nameplate MVA rating at rated power factor for all applications, the setting criteria are based on the maximum expected generator output. Table 1, Option 19 establishes criteria for phase directional overcurrent relays that are directional toward the Transmission system to prevent Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant from tripping during the dynamic conditions anticipated by this standard. Option 19 applies a 1.0 per unit line nominal voltage at the relay location to calculate the current from the maximum aggregate nameplate MVA. For Option 19, the overcurrent element shall be set greater than 130 percent of the calculated current derived from the maximum aggregate nameplate MVA output at rated power factor including the Mvar output of any static or dynamic Reactive Power devices. This is determined by summing the total MW and Mvar capability of the generation equipment behind the relay and any static or dynamic Reactive Power devices that contribute to the power flow through the relay. This is a simple calculation that approximates the stressed system conditions.


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Example Calculations Introduction

Example Calculations.

Input Descriptions Input Values

Synchronous Generator nameplate (MVA @ rated pf): _ 903

0.85

Generator rated voltage (Line‐to‐Line): _ 22

Real Power output in MW as reported to the TP: _ 700.0

Generator step‐up (GSU) transformer rating: 903

GSU transformer reactance (903 MVA base): 12.14%

GSU transformer MVA base: 767.6

GSU transformer turns ratio: 22346.5

High‐side nominal system voltage (Line‐to‐Line): 345

Current transformer (CT) ratio: 250005

Potential transformer (PT) ratio low‐side: 2001

PT ratio high‐side: _20001

Unit auxiliary transformer (UAT) nameplate: 60

UAT low‐side voltage: 13.8

UAT CT ratio: 50005

CT high voltage ratio: _20005

Reactive Power output of static reactive device: 15


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Reactive Power output of static reactive device generation: _ 5

Asynchronous generator nameplate (MVA @ rated pf): _ 40

0.85

Asynchronous CT ratio: _ 50005

Asynchronous high voltage CT ratio: _ _ 3005

CT remote substation bus _ _ 20005


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Example Calculations: Option 1a

Option 1a represents the simplest calculation for synchronous generators applying a phase distance relay (e.g., 21) directional toward the Transmission system.

Real Power output (P):

Eq. (1) _

903 0.85

767.6

Reactive Power output (Q):

Eq. (2) 150%

1.50 767.6

1151.3

Option 1a, Table 1 – Bus Voltage, calls for a 0.95 per unit of the high‐side nominal voltage for the generator bus voltage (Vgen):

Eq. (3) 0.95 . .

0.95 345

22346.5

20.81

Apparent power (S):

Eq. (4) _

700.0 1151.3

1347.458.7°

Primary impedance (Zpri):

Eq. (5) ∗

20.811347.4 58.7°


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0.32158.7°Ω

Secondary impedance (Zsec):

Eq. (6)

0.32158.7°Ω

0.32158.7°Ω 25

8.03558.7°Ω

To satisfy the 115% margin in Option 1a:

Eq. (7) 115%

8.03558.7° Ω1.15

6.987358.7° Ω

58.7°

Assume a Mho distance impedance relay with a maximum torque angle (MTA) set at 85°, then the maximum allowable impedance reach is:

Eq. (8) | |

cos

6.9873Ωcos 85.0° 58.7°

6.9873Ω0.896

7.79385.0° Ω


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Example Calculations: Options 1b and 7b

Option 1b represents a more complex, more precise calculation for synchronous generators applying a phase distance relay (e.g., 21) directional toward the Transmission system. This option requires calculating low‐side voltage taking into account voltage drop across the GSU transformer. Similarly these calculations may be applied to Option 7b for GSU transformers applying a phase distance relay (e.g., 21) directional toward the Transmission system.


Eq. (9) _

903 0.85

767.6


Eq. (10) 150%

1.50 767.6

1151.3

Convert Real Power, Reactive Power, and transformer reactance to per unit values on a 767.6 MVA base (MVAbase):


Eq. (11) _

700.0767.6

0.91 . .


Eq. (12)

1151.3767.6

1.5 . .


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Transformer impedance (Xpu):

Eq. (13)

12.14%

767.6903

0.1032 . .

Using the formula below; calculate the low‐side GSU transformer voltage (Vlow‐side) using 0.85 p.u. high‐side voltage (Vhigh‐side). Estimate initial low‐side voltage to be 0.95 p.u. and repeat the calculation as necessary until Vlow‐side converges. A convergence of less than one percent (<1%) between iterations is considered sufficient:

Eq. (14) sin| |

sin

0.91 0.10320.95 0.85

6.7°

Eq. (15)

| |cos cos 4

2

| |

|0.85| cos 6.7° |0.85| cos 6.7° 4 1.5 0.10322

| |

|0.85| 0.9931 √0.7225 0.9864 0.61922

| |

0.8441 1.15412

| | 0.9991 . .


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Use the new estimated Vlow‐side value of 0.9991 per unit for the second iteration:

Eq. (16) sin| |

sin

0.91 0.10320.9991 0.85

6.3°

Eq. (17)

| |cos cos 4

2

| |

|0.85| cos 6.3° |0.85| cos 6.3° 4 1.5 0.10322

| |

|0.85| 0.9940 √0.7225 0.9880 0.61922

| |

0.8449 1.15462

| | 0.9998 . .

To account for system high‐side nominal voltage and the transformer tap ratio:

Eq. (18) | |

0.9998 . . 345

22346.5

21.90

Apparent power (S):

Eq. (19) _

700.0 1151.3

1347.458.7° MVA


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Eq. (20) ∗

21.901347.4 58.7°

0.35658.7°Ω


Eq. (21)

0.35658.7°Ω

0.35658.7°Ω 25

8.90058.7°Ω

To satisfy the 115% margin in Options 1b and 7b:

Eq. (22) 115%

8.90058.7° Ω1.15

7.7458.7°Ω

58.7°


Eq. (23) | |

cos

7.74Ωcos 85.0° 58.7°


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7.74Ω0.8965

8.63385.0°Ω

Example Calculations: Options 1c and 7c

Option 1c represents a more involved, more precise setting of the impedance element. This option requires determining maximum generator Reactive Power output during field‐forcing and the corresponding generator bus voltage. Once these values are determined, the remainder of the calculation is the same as Options 1a and 1b.

The generator Reactive Power and generator bus voltage are determined by simulation. The maximum Reactive Power output on the low‐side of the GSU transformer during field‐forcing is used as this value will correspond to the lowest apparent impedance. The corresponding generator bus voltage is also used in the calculation. Note that although the excitation limiter reduces the field, the duration of the Reactive Power output achieved for this condition is sufficient to operate a phase distance relay.

In this simulation the following values are derived:

827.4

_ 0.989 _ 21.76 V

The other value required is the Real Power output which is modeled in the simulation at 100% of the gross MW capability reported to the Transmission Planner. In this case:

_ 700.0


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Apparent power (S):

Eq. (24) _

700.0 827.4

1083.849.8° MVA


Eq. (25) _∗

21.761083.8 49.8°

0.43749.8°Ω


Eq. (26)

0.43749.8°Ω


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0.43749.8°Ω 25

10.9249.8°Ω

To satisfy the 115% margin in the requirement in Options 1c and 7c:

Eq. (27) 115%

10.9249.8° Ω1.15

9.5049.8° Ω

49.8°


Eq. (28) | |

cos

9.50Ωcos 85.0° 49.8°

9.50Ω0.8171

11.6385.0°Ω


Option 2a represents the simplest calculation for synchronous generators applying a phase overcurrent (e.g., 50, 51, or 51V‐R) relay:


Eq. (29) _

903 0.85

767.6


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Eq. (30) 150%

1.50 767.6

1151.3


Eq. (31) 0.95 . .

0.95 345

22346.5

20.81

Apparent power (S):

Eq. (32) _

700.0 1151.3

1347.458.7°

Primary current (Ipri):

Eq. (33) √3

1347.41.73 20.81

37383

Secondary current (Isec):

Eq. (34)

37383250005


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7.477


Eq. (35) 115%

7.477 1.15

8.598

Example Calculations: Option 2b

Option 2b represents a more complex calculation for synchronous generators applying a phase overcurrent (e.g., 50, 51, or 51V‐R) relay:


Eq. (36) _

903 0.85

767.6


Eq. (37) 150%

1.50 767.6

1151.3

Convert Real Power, Reactive Power, and transformer reactance to per unit values on 767.6 MVA base (MVAbase).


Eq. (38) _

700.0767.6

0.91 . .


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Eq. (39)

1151.3767.6

1.5 . .

Transformer impedance:

Eq. (40)

12.14%

767.6903

0.1032 . .


Eq. (41) sin| |

sin

0.91 0.10320.95 0.85

6.7°

Eq. (42)

| |cos cos 4

2

| |

|0.85| cos 6.7° |0.85| cos 6.7° 4 1.5 0.10322


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| |

|0.85| 0.9931 √0.7225 0.9864 0.61922

| |

0.8441 1.15412

| | 0.9991 . .


Eq. (43) sin| |

sin

0.91 0.10320.9991 0.85

6.3°

Eq. (44)

| |cos cos 4

2

| |

|0.85| cos 6.3° |0.85| cos 6.3° 4 1.5 0.10322

| |

|0.85| 0.9940 √0.7225 0.9880 0.61922

| |

0.8449 1.15462

| | 0.9998 . .


Eq. (45) | |

0.9998 . . 345

22346.5

21.90


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Apparent power (S):

Eq. (46) _

700.0 1151.3

1347.458.7°


Eq. (47) √3

1347.41.73 21.90

35553


Eq. (48)

35553250005

7.111

To satisfy the 115% margin in Option 2b:

Eq. (49) 115%

7.111 1.15

8.178


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Example Calculations: Option 2c

Option 2c represents a more involved, more precise setting of the overcurrent element for the phase overcurrent (e.g., 50, 51, or 51V‐R) relay. This option requires determining maximum generator Reactive Power output during field‐forcing and the corresponding generator bus voltage. Once these values are determined, the remainder of the calculation is the same as Options 2a and 2b.

The generator Reactive Power and generator bus voltage are determined by simulation. The maximum Reactive Power output on the low‐side of the GSU transformer during field‐forcing is used as this value will correspond to the highest current. The corresponding generator bus voltage is also used in the calculation. Note that although the excitation limiter reduces the field, the duration of the Reactive Power output achieved for this condition is sufficient to operate a voltage‐restrained phase overcurrent relay.


827.4

_ 0.989 _ 21.76


_ 700.0


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Apparent power (S):

Eq. (50) _

700.0 827.4

1083.849.8° MVA


Eq. (51) √3 _

1083.81.73 21.76

28790


Eq. (52)

28790250005

5.758

To satisfy the 115% margin in Option 2c:

Eq. (53) 115%

5.758 1.15

6.622

Example Calculations: Options 3 and 6

Option 3 represents the only calculation for synchronous generators applying a phase time overcurrent (e.g., 51V‐C) relay (Enabled to operate as a function of voltage). Similarly, Option 6 uses the same calculation for asynchronous generators.


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Options 3 and 6, Table 1 – Bus Voltage, calls for a 1.0 per unit of the high‐side nominal voltage for the generator bus voltage (Vgen):

Eq. (54) 1.0 . .

1.0 345

22346.5

21.9

The voltage setting shall be set less than 75% of the generator bus voltage:

Eq. (55) 75%

21.9 0.75

16.429

Example Calculations: Option 4

This represents the calculation for an asynchronous generator (including inverter‐based installations) applying a phase distance relay (e.g., 21) directional toward the Transmission system.


Eq. (56) _

40 0.85

34.0


Eq. (57) _ sin cos

40 sin cos 0.85

21.1


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Option 4, Table 1 – Bus Voltage, calls for a 1.0 per unit of the high‐side nominal voltage for the generator bus voltage (Vgen):

Eq. (58) 1.0 . .

1.0 345

22346.5

21.9

Apparent power (S):

Eq. (59)

34.0 21.1

40.031.8°


Eq. (60) ∗

21.940.0 31.8°

11.9931.8°Ω


Eq. (61) _

11.9931.8°Ω

11.9931.8°Ω 5

59.9531.8°Ω

To satisfy the 130% margin in Option 4:

Eq. (62) 130%


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59.9531.8° Ω1.30

46.1231.8° Ω

31.8°


Eq. (63) | |

cos

46.12Ωcos 85.0° 31.8°

46.12Ω0.599

77.085.0°Ω


This represents the calculation for three asynchronous generators applying a phase overcurrent (e.g., 50, 51, or 51V‐R) relay. In this application it was assumed that 20 Mvar of total static compensation was added.


Eq. (64) 3 _

3 40 0.85

102.0


Eq. (65) _ 3 _ sin cos

15 5 3 40 sin cos 0.85

83.2


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Eq. (66) 1.0 . .

1.0 345

22346.5

21.9

Apparent power (S):

Eq. (67)

102.0 83.2

131.639.2°


Eq. (68) ∗

√3

131.6 39.2°1.73 21.9

3473 39.2°


Eq. (69) _

3473 39.2°50005

3.473 39.2°


Eq. (70) 130%

3.473 39.2° 1.30


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4.52 39.2°


Similarly to Option 5a, this example represents the calculation for three asynchronous generators applying a phase overcurrent (e.g., 50, 51, or 51V‐R) relay. In this application it was assumed that 20 Mvar of total static compensation was added.


Eq. (71) 3 _

3 40 0.85

102.0


Eq. (72) _ 3 _ sin cos

15 5 3 40 sin cos 0.85

83.2

Option 5b, Table 1 – Bus Voltage, calls for a 1.0 per unit of the high‐side nominal voltage for the generator bus voltage (Vgen):

Eq. (73) 1.0 . .

1.0 345

22346.5

21.9

Apparent power (S):

Eq. (74)

102.0 83.2

131.639.2°


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Eq. (75) ∗

√3

131.6 39.2°1.73 21.9

3473 39.2°


Eq. (76) _

3473 39.2°50005

3.473 39.2°

To satisfy Option 5b, the overcurrent element shall not infringe upon the resource capability (including the Mvar output of the resource and any static or dynamic reactive power devices) with worst case documented tolerances applied between the maximum resource capability and the overcurrent element (see Figure A).

Example Calculations: Options 7a and 10

These examples represent the calculation for a mixture of asynchronous (i.e., Option 10) and synchronous (i.e., Option 7a) generation (including inverter‐based installations) applying a phase distance relay (e.g., 21) directional toward the Transmission system. In this application it was assumed 20 Mvar of total static compensation was added.

Synchronous Generation (Option 7a)

Real Power output ( ):

Eq. (77) _

903 0.85

767.6


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Reactive Power output ( ):

Eq. (78) 150%

1.50 767.6

1151.3

Apparent power (SSynch):

Eq. (79) _

700.0 1151.3

Asynchronous Generation (Option 10)

Real Power output (PAsynch):

Eq. (80) 3 _

3 40 0.85

102.0

Reactive Power output (QAsynch):

Eq. (81) _ 3 _ sin cos

15 5 3 40 sin cos 0.85

83.2

Apparent power (SAsynch):

Eq. (82)

102.0 83.2


Draft 1 | June 7, 2017 81 of 112


Options 7a and 10, Table 1 – Bus Voltage, Option 7a specifies 0.95 per unit of the high‐side nominal voltage for the generator bus voltage and Option 10 specifies 1.0 per unit of the high‐side nominal voltage for generator bus voltage. Due to the presence of the synchronous generator, the 0.95 per unit bus voltage will be used as (Vgen) as it results in the most conservative voltage:

Eq. (83) 0.95 . .

0.95 345

22346.5

20.81

Apparent power (S) accounted for 115% margin requirement for a synchronous generator and 130% margin requirement for an asynchronous generator:

Eq. (84) 115% _ 130%

1.15 700.0 1151.3 1.30 102.0 83.2

1711.856.8°


Eq. (85) ∗

20.811711.8 56.8°

0.252756.8°Ω


Eq. (86)

0.252756.8°Ω

0.252756.8°Ω 25

6.3256.8°Ω


Draft 1 | June 7, 2017 82 of 112


No additional margin is needed because the synchronous apparent power has been multiplied by 1.15 (115%) and the asynchronous apparent power has been multiplied by 1.30 (130%) in Equation 84 to satisfy the margin requirements in Options 7a and 10.

Eq. (87) 100%

6.3256.8° Ω1.00

6.3256.8° Ω

56.8°


Eq. (88) | |

cos

6.32Ωcos 85.0° 56.8°

6.32Ω0.881

7.1785.0°Ω

Example Calculations: Options 8a and 9a

Options 8a and 9a represents the simplest calculation for synchronous generators applying a phase overcurrent (e.g., 50, 51, or 67) relay. The following uses the GENSynch_nameplate value to represent an “aggregate” value to illustrate the option:


Eq. (89) _

903 0.85

767.6


Draft 1 | June 7, 2017 83 of 112



Eq. (90) 150%

1.50 767.6

1151.3

Options 8a and 9a, Table 1 – Bus Voltage, calls for a generator bus voltage corresponding to 0.95 per unit of the high‐side nominal voltage times the turns ratio of the generator step‐up transformer generator bus voltage (Vgen):

Eq. (91) 0.95 . .

0.95 345

22346.5

20.81

Apparent power (S):

Eq. (92) _

700.0 1151.3

1347.458.7°


Eq. (93) √3

1347.41.73 20.81

37383


Eq. (94)


Draft 1 | June 7, 2017 84 of 112


37383250005

7.477

To satisfy the 115% margin in Options 8a and 9a:

Eq. (95) 115%

7.477 1.15

8.598


Options 8b and 9b represents a more precise calculation for synchronous generators applying a phase overcurrent (e.g., 50, 51, or 67) relay. The following uses the GENSynch_nameplate value to represent an “aggregate” value to illustrate the option:


Eq. (96) _

903 0.85

767.6


Eq. (97) 150%

1.50 767.6

1151.3

Convert Real Power, Reactive Power, and transformer reactance to per unit values on 767.6 MVA base (GSU Transformer MVAbase).


Eq. (98) _


Draft 1 | June 7, 2017 85 of 112


700.0767.6

0.91 . .


Eq. (99)

1151.3767.6

1.5 . .


Eq. (100)

12.14%

767.6903

0.1032 . .


Eq. (101) sin| |

sin

0.91 0.10320.95 0.85

Eq. (102)

| |cos cos 4

2

| |

|0.85| cos 6.7° |0.85| cos 6.7° 4 1.5 0.10322


Draft 1 | June 7, 2017 86 of 112


| |

|0.85| 0.9931 √0.7225 0.9864 0.61922

| |

0.8441 1.15412

| | 0.9991 . .


Eq. (103) sin| |

sin

0.91 0.10320.9991 0.85

6.3°

Eq. (104)

| |cos cos 4

2

| |

|0.85| cos 6.3° |0.85| cos 6.3° 4 1.5 0.10322

| |

|0.85| 0.9940 √0.7225 0.9880 0.61922

| |

0.8449 1.15462

| | 0.9998 . .


Eq. (105) | |

0.9998 . . 345

22346.5

21.90


Draft 1 | June 7, 2017 87 of 112


Apparent power (S):

Eq. (106) _

700.0 1151.3

1347.458.7°


Eq. (107) √3

1347.41.73 21.90

35553


Eq. (108)

35553250005

7.111


Eq. (109) 115%

7.111 1.15

8.178


Draft 1 | June 7, 2017 88 of 112

Example Calculations: Options 8a, 9a, 11, and 12

This example represents the calculation for a mixture of asynchronous and synchronous generators applying a phase overcurrent (e.g., 50, 51, or 67) relays. In this application it was assumed 20 Mvar of total static compensation was added. The current transformers (CT) are located on the low‐side of the GSU transformer.

Synchronous Generation (Options 8a and 9a)

Real Power output (PSynch):

Eq. (110) _

903 .85

767.6

Reactive Power output (QSynch):

Eq. (111) 150%

1.50 767.6

1151.3


Eq. (112) _

700.0 1151.3

1347.458.7°

Option 8a, Table 1 – Bus Voltage calls for a 0.95 per unit of the high‐side nominal voltage as a basis for generator bus voltage (Vgen):

Eq. (113) 0.95 . .

0.95 345

22346.5

20.81


Draft 1 | June 7, 2017 89 of 112


Primary current (Ipri‐sync):

Eq. (114) 115% ∗

√3

1.15 1347.4 58.7°1.73 20.81

43061 58.7°

Asynchronous Generation (Options 11 and 12)


Eq. (115) 3 _

3 40 0.85

102.0


Eq. (116) _ _ sin cos

15 5 3 40 sin cos 0.85

83.2

Option 11, Table 1 – Bus Voltage, calls for a 1.0 per unit of the high‐side nominal voltage for the generator bus voltage (Vgen), however due to the presence of synchronous generator 0.95 per unit bus voltage will be used:

Eq. (117) 0.95 . .

0.95 345

22346.5

20.81


Eq. (118) 130%

1.30 102.0 83.2


Draft 1 | June 7, 2017 90 of 112


171.139.2°

Primary current (Ipri‐async):

Eq. (119) √3

171.1 39.2°1.73 20.81

4755 39.2°


Eq. (120)

43061 58.7°250005

4755 39.2°250005

9.514 56.8°

No additional margin is needed because the synchronous apparent power has been multiplied by 1.15 (115%) in Equation 114 and the asynchronous apparent power has been multiplied by 1.30 (130%) in Equation 118.

Eq. (121) 100%

9.514 56.8° 1.00

9.514 56.8°


This example uses Option 15b as a simulation example for a synchronous generator applying a phase overcurrent relay (e.g., 50, 51, or 67). In this application the same synchronous generator is modeled as for Options 1c, 2c, and 7c. The CTs are located on the low‐side of the GSU transformer.

The generator Reactive Power and generator bus voltage are determined by simulation. The maximum Reactive Power output on the low‐side of the GSU transformer, during field‐forcing, is used since this value will correspond to the highest current. The corresponding


Draft 1 | June 7, 2017 91 of 112


generator bus voltage is also used in the calculation. Note that although the excitation limiter reduces the field, the duration of the Reactive Power output achieved for this condition is sufficient to operate a phase overcurrent relay.


827.4

_ 0.989 21.76


700.0

Apparent power (S):

Eq. (122) _

700.0 827.4

1083.849.8°


Draft 1 | June 7, 2017 92 of 112



Eq. (123) √3 _

1083.81.73 21.76

28790


Eq. (124)

28790250005

5.758

To satisfy the 115% margin in Options 8c and 9c:

Eq. (125) 115%

5.758 1.15

6.622

Example Calculations: Option10

This example represents the calculation for three asynchronous generators (including inverter‐based installations) applying a phase distance relay (e.g., 21) directional toward the Transmission system. In this application it was assumed 20 Mvar of total static compensation was added.


Eq. (126) 3 _

3 40 0.85


Draft 1 | June 7, 2017 93 of 112


102.0


Eq. (127) _ 3 _ sin cos

15 5 3 40 sin cos 0.85

83.2


Eq. (128) 1.0 . .

1.0 345

22346.5

21.9

Apparent power (S):

Eq. (129)

102.0 83.2

131.639.2°


Eq. (130) ∗

21.9131.6 39.2°

3.64439.2°Ω


Eq. (131) _


Draft 1 | June 7, 2017 94 of 112


3.64439.2°Ω

3.64439.2°Ω 5

18.2239.2°Ω


Eq. (132) 130%

18.2239.2° Ω1.30

14.0239.2° Ω

39.2°


Eq. (133) | |

cos

14.02Ωcos 85.0° 39.2°

14.02Ω0.6972

20.1185.0°Ω


Option 11 represents the calculation for a GSU transformer applying a phase overcurrent (e.g., 50 or 51) relay connected to three asynchronous generators. Similarly, these calculations can be applied to Option 12 for a phase directional overcurrent relay (e.g., 67) directional toward the Transmission system. In this application it was assumed 20 Mvar of total static compensation was added.


Draft 1 | June 7, 2017 95 of 112



Eq. (134) 3 _

3 40 0.85

102.0


Eq. (135) _ 3 _ sin cos

15 5 3 40 sin cos 0.85

83.2


Eq. (136) 1.0 . .

1.0 345

22346.5

21.9

Apparent power (S):

Eq. (137)

102.0 83.2

131.639.2°


Eq. (138) ∗

√3

131.6 39.2°1.73 21.9

3473 39.2°


Draft 1 | June 7, 2017 96 of 112



Eq. (139) _

3473 39.2°50005

3.473 39.2°

To satisfy the 130% margin in Options 11 and12:

Eq. (140) 130%

3.473 39.2° 1.30

4.515 39.2°

Example Calculations: Options 13a and 13b

Option 13a for the UAT assumes the maximum nameplate rating of the winding is utilized for the purposes of the calculations and the appropriate voltage. Similarly, Option 13b uses the measured current while operating at the maximum gross MW capability reported to the Transmission Planner.


Eq. (141) √3

601.73 13.8

2510.2


Eq. (142)


Draft 1 | June 7, 2017 97 of 112


2510.250005

2.51A

To satisfy the 150% margin in Options 13a:

Eq. (143) 150%

2.51 1.50

3.77


Option 14a represents the calculation for Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant that connected to synchronous generation. In this example, the Element is protected by a phase distance (e.g., 21) relay directional toward the Transmission system. The CTs are located on the high‐side of the GSU transformer.


Eq. (144) _

903 0.85

767.6


Eq. (145) 120%

1.20 767.6

921.1

Option 14a, Table 1 – Bus Voltage, calls for a 0.85 per unit of the line nominal voltage for the GSU transformer voltage (Vnom):

Eq. (146) 0.85 . .


Draft 1 | June 7, 2017 98 of 112


0.85 345

293.25

Apparent power (S):

Eq. (147) _

700.0 921.1

1157.052.77°

52.77°


Eq. (148) ∗

293.251157.0 52.77°

74.33552.77° Ω


Eq. (149) _

_

74.33552.77° Ω

74.33552.77° Ω 0.2

14.86752.77° Ω


Eq. (150) 115%

14.86752.77° Ω1.15


Draft 1 | June 7, 2017 99 of 112


12.92852.77° Ω

52.77°


Eq. (151) | |

cos

12.928Ωcos 85.0° 52.77°

12.928Ω0.846

15.28385.0° Ω


Option 14b represents the simulation for Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant connected to synchronous generation. In this example, the Element is protected by a phase distance (e.g., 21) relay directional toward the Transmission system. The CTs are located on the high‐side of the GSU transformer.

The Reactive Power flow and high‐side bus voltage are determined by simulation. The maximum Reactive Power output on the high‐side of the GSU transformer during field‐forcing is used as this value will correspond to the lowest apparent impedance. The corresponding high‐side bus voltage is also used in the calculation. Note that although the excitation limiter reduces the field, the duration of the Reactive Power output achieved for this condition is sufficient to operate a phase distance relay.


703.6

_ 0.908 313.3


Draft 1 | June 7, 2017 100 of 112



700.0

Apparent power (S):

Eq. (152) _

700.0 703.6

992.545.1°

45.1°


Eq. (153) _∗

313.3992.5 45.1°

98.9045.1°Ω


Draft 1 | June 7, 2017 101 of 112



Eq. (154) _

_

98.9045.1°Ω

98.9045.1°Ω 0.2

19.7845.1°Ω


Eq. (155) 115%

19.7845.1° Ω1.15

17.2045.1° Ω

45.1°


Eq. (156) | |

cos

17.20Ωcos 85.0° 45.1°

17.20Ω0.767

22.4285.0° Ω


Draft 1 | June 7, 2017 102 of 112


Options 15a and 16a represent the calculation for Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant connected to synchronous generation. Option 15a represents applying a phase time overcurrent relay (e.g., 51) and/or phase instantaneous overcurrent supervisory elements (e.g., 50) associated with current‐based, communication‐assisted schemes where the scheme is capable of tripping for loss of communications installed on the high‐side of the GSU transformer and remote end of the line. Option 16a represents applying a phase directional instantaneous overcurrent supervisory element (e.g., 67) associated with current‐based, communication‐assisted schemes where the scheme is capable of tripping for loss of communications directional toward the Transmission system installed on the high‐side of the GSU and at the remote end of the line and/or a phase time directional overcurrent relay (e.g., 67) directional toward the Transmission system installed on the high‐side of the GSU transformer and remote end of the line.

Example calculations are provided for the case, where potential transformers (PT) and current transformers (CT) are located at the high‐side of the GSU transformer. The 0.85 per unit of the line nominal voltage at the relay location will be at the high‐side of the GSU transformer. Example calculations are also provided for the case where PTs and CTs are located at the remote end of the line and the 0.85 per unit of the line nominal voltage will be at the remote bus location.

Calculations at the high-side of the GSU transformer.


Eq. (157) _

903 0.85

767.6


Eq. (158) 120%

1.20 767.6

921.12

Option 15a, Table 1 – Bus Voltage, calls for a 0.85 per unit of the line nominal voltage:

Eq. (159) 0.85 . .

0.85 345


Draft 1 | June 7, 2017 103 of 112


293.25

Apparent power (S):

Eq. (160) _

700.0 921.12

115752.8°


Eq. (161) ∗

√3

1157∠ 52.8°1.73 293.25

2280.6∠ 52.8°


Eq. (162) _

2280.6∠ 52.8°20005

5.701∠ 52.8°


Eq. (163) 115%

5.701∠ 52.8° 1.15

6.56∠ 52.8°

Calculations at the remote end of the line from the plant.


Eq. (164) _


Draft 1 | June 7, 2017 104 of 112


903 0.85

767.6


Eq. (165) 120%

1.20 767.6

921.12

Option 15a and 16a, Table 1 – Bus Voltage, calls for a 0.85 per unit of the line nominal voltage at the relay location, in this example the relay location is at the remote substation bus.

Eq. (166) _ _ 0.85 . .

_ _ 0.85 345

_ _ 293.25

Apparent power (S):

Eq. (167) _

700.0 921.12

115752.8°


Eq. (168) ∗

√3 _ _

1157∠ 52.8°1.73 293.25

2280.6∠ 52.8°


Eq. (169) _ _


Draft 1 | June 7, 2017 105 of 112


2280.6∠ 52.8°20005

5.701∠ 52.8°


Eq. (170) 115%

5.701∠ 52.8° 1.15

6.56∠ 52.8°


Options 15b and 16b represent the calculation for Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant connected to synchronous generation. Option 15b represents applying a phase time overcurrent relay (e.g., 51) and/or phase instantaneous overcurrent supervisory elements (e.g., 50) associated with current‐based, communication‐assisted schemes where the scheme is capable of tripping for loss of communications installed on the high‐side of the GSU transformer and remote end of the line. Option 16b represents applying a phase directional instantaneous overcurrent supervisory element (e.g., 67) associated with current‐based, communication‐assisted schemes where the scheme is capable of tripping for loss of communications directional toward the Transmission system installed on the high‐side of the GSU and at the remote end of the line and/or a phase directional time overcurrent relay (e.g., 67) directional toward the Transmission system installed on the high‐side of the GSU and remote end of the line.

Example calculations are provided for the case, where PTs and CTs are located at the remote end of the line from the plant. The 0.85 per unit of the line nominal voltage is applied at the remote end of the line.

The Reactive Power flow and high‐side bus voltage are determined by simulation. The maximum Reactive Power output on the high‐side of the GSU transformer during field‐forcing is used as this value will correspond to the lowest apparent impedance. The corresponding high‐side bus voltage is also used in the calculation. Note that although the excitation limiter reduces the field, the duration of the Reactive Power output achieved for this condition is sufficient to operate a phase overcurrent relay.


Draft 1 | June 7, 2017 106 of 112



703.6

_ 0.908 313.3


700.0

Apparent power (S):

Eq. (171) _

700.0 703.6

992.545.1°


Eq. (172) ∗

√3 _

992.5 45.1°1.73 313.3


Draft 1 | June 7, 2017 107 of 112


1831.2∠ 45.1°


Eq. (173) _

1831.2∠ 45.1°20005

4.578∠ 45.1°


Eq. (174) 115%

4.578∠ 45.1° 1.15

5.265∠ 45.1°


Option 17 represents the calculation for Elements that connect a GSU transformer for three asynchronous generators to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant that is applying a phase distance relay (e.g., 21) directional toward the Transmission system. In this application it was assumed 20 Mvar of total static compensation was added.


Eq. (175) 3 _

3 40 0.85

102.0


Eq. (176) _

3 _ sin cos


Draft 1 | June 7, 2017 108 of 112


15 5 3 40 sin cos 0.85

83.2

Option 17, Table 1 – Bus Voltage, calls for a 1.0 per unit of the line nominal voltage for the bus voltage (Vbus):

Eq. (177) 1.0 . .

1.0 345

345.0

Apparent power (S):

Eq. (178)

102.0 83.2

131.639.2°


Eq. (179) ∗

345.0131.6 39.2°

904.439.2°Ω


Eq. (180) _ _

_

904.439.2°Ω

904.439.2°Ω 0.03

27.1339.2°Ω


Draft 1 | June 7, 2017 109 of 112



Eq. (181) 130%

27.1339.2° Ω1.30

20.86939.2° Ω

39.2°

Assume a Mho distance impedance relay with a maximum torque angle (MTA) set at 85°, and then the maximum allowable impedance reach is:

Eq. (182) | |

cos

20.869Ωcos 85.0° 39.2°

20.869Ω0.697

29.94185.0° Ω


Option 18 represents the calculation for relays on Elements that connect a GSU transformer for three asynchronous generators to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. Option 18 represents applying a phase time overcurrent (e.g., 51) and/or phase instantaneous overcurrent supervisory elements (e.g., 50) associated with current‐based, communication‐assisted schemes where the scheme is capable of tripping for loss of communications installed on the high‐side of the GSU transformer and remote end of the line.

Similarly, Option 19 may also be applied here for the phase directional overcurrent relays (e.g., 67) directional toward the Transmission system for Elements that connect a GSU transformer and remote end of the line to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. In this application it was assumed 20 Mvar of total static compensation was added.


Draft 1 | June 7, 2017 110 of 112



Eq. (183) 3 _

3 40 0.85

102.0


Eq. (184) _

3 _ sin cos

15 5 3 40 sin cos 0.85

83.2

Options 18 and 19, Table 1 – Bus Voltage, calls for a 1.0 per unit of the line nominal voltage (Vbus):

Eq. (185) 1.0 . .

1.0 345

345

Apparent power (S):

Eq. (186)

102.0 83.2

131.639.2°


Eq. (187) ∗

√3

131.6 39.2°1.73 345

220.5 39.2°


Draft 1 | June 7, 2017 111 of 112



Eq. (188) _ _

220.5 39.2°3005

3.675 39.2°

To satisfy the 130% margin in Options 18 and 19:

Eq. (189) 130%

3.675 39.2° 1.30

4.778 39.2°

End of calculations


Draft 1 | June 7, 2017 112 of 112

Rationale During development of this standard, text boxes were embedded within the standard to explain the rationale for various parts of the standard. Upon BOT approval, the text from the rationale text boxes was moved to this section. Rationale for R1 Requirement R1 is a risk‐based requirement that requires the responsible entity to be aware of each protective relay subject to the standard and applies an appropriate setting based on its calculations or simulation for the conditions established in Attachment 1. The criteria established in Attachment 1 represent short‐duration conditions during which generation Facilities are capable of providing system reactive resources, and for which generation Facilities have been historically recorded to disconnect, causing events to become more severe. The term, “while maintaining reliable fault protection” in Requirement R1 describes that the responsible entity is to comply with this standard while achieving their desired protection goals. Refer to the Guidelines and Technical Basis, Introduction, for more information.


Draft 1 | June 7, 2017 1 of 129


This section is maintained by the drafting team during the development of the standard and will be removed when the standard is adopted by the NERC Board of Trustees (Board).

Description of Current Draft The standard drafting team (PRC_025) is posting Draft 1 of PRC‐025‐2, Generator Relay Loadability for a 45‐day formal comment period and initial ballot in the last ten days of the comment period.


The Standards Committee (SC) authorized the SAR for posting September 14, 2016

Draft 1 of the Standards Authorization Request (SAR) was posted for a 30‐day formal comment period

September 16, 2016 through October 18, 2016

Draft 2 of the SAR was posted for a 15‐day informal comment period March 20, 2017 through April 3, 2017

The SC accepted the SAR and appointed the SAR drafting team as the standard drafting team (SDT)

April 19, 2017


45‐day formal comment period with initial ballot July 2017

45‐day formal comment period with additional ballot September 2017

10‐day final ballot January 2018

Board adoption February 2018

New or Modified Term(s) Used in NERC Reliability Standards This section includes all new or modified terms used in the proposed standard that will be included in the Glossary of Terms Used in NERC Reliability Standards upon applicable regulatory approval. Terms used in the proposed standard that are already defined and are not being modified can be found in the Glossary of Terms Used in NERC Reliability Standards. The new or revised terms listed below will be presented for approval with the proposed standard. Upon Board adoption, this section will be removed.

Agenda Item 7(ii)Standards CommitteeJuly 19, 2017


Draft 1 | June 7, 2017 2 of 129

Term(s): None.

PRC-025-1— Generator Relay Loadability

3 of 129

A. Introduction 1. Title: Generator Relay Loadability

2. Number: PRC‐025‐12

3. Purpose: To set load‐responsive protective relays associated with generation Facilities at a level to prevent unnecessary tripping of generators during a system disturbance for conditions that do not pose a risk of damage to the associated equipment.

4. Applicability:

4.1. Functional Entities:

4.1.1. Generator Owner that applies load‐responsive protective relays at the terminals of the Elements listed in 3.2, Facilities.

4.1.2. Transmission Owner that applies load‐responsive protective relays at the terminals of the Elements listed in 3.2, Facilities.

4.1.3. Distribution Provider that applies load‐responsive protective relays at the terminals of the Elements listed in 3.2, Facilities.

4.2. Facilities: The following Elements associated with Bulk Electric System (BES) generating units and generating plants, including those generating units and generating plants identified as Blackstart Resources in the Transmission Operator’s system restoration plan:

4.2.1. Generating unit(s).

4.2.2. Generator step‐up (i.e., GSU) transformer(s).

4.2.3. Unit auxiliary transformer(s) (UAT) that supply overall auxiliary power necessary to keep generating unit(s) online.1

4.2.4. Elements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. Elements may also supply generating plant loads.

4.2.5. Elements utilized in the aggregation of dispersed power producing resources.

5. Effective Date: See Implementation Plan

1 These transformers are variably referred to as station power, unit auxiliary transformer(s) (UAT), or station service transformer(s) used to provide overall auxiliary power to the generator station when the generator is running. Loss of these transformers will result in removing the generator from service. Refer to the PRC‐025‐12 Guidelines and Technical Basis for more detailed information concerning unit auxiliary transformers.


4 of 129

5. Background:

6. After analysis of many of the major disturbances in the last 25 years on the North American interconnected power system, generators have been found to have tripped for conditions that did not apparently pose a direct risk to those generators and associated equipment within the time period where the tripping occurred. This tripping has often been determined to have expanded the scope and/or extended the duration of that disturbance. This was noted to be a serious issue in the August 2003 “blackout” in the northeastern North American continent.2

During the recoverable phase of a disturbance, the disturbance may exhibit a “voltage disturbance” behavior pattern, where system voltage may be widely depressed and may fluctuate. In order to support the system during this transient phase of a disturbance, this standard establishes criteria for setting load‐responsive protective relays such that individual generators may provide Reactive Power within their dynamic capability during transient time periods to help the system recover from the voltage disturbance. The premature or unnecessary tripping of generators resulting in the removal of dynamic Reactive Power exacerbates the severity of the voltage disturbance, and as a result changes the character of the system disturbance. In addition, the loss of Real Power could initiate or exacerbate a frequency disturbance.

7. Standard Only Definition: None.

7.1. Effective Date: See Implementation Plan

B. Requirements and Measures R1. Each Generator Owner, Transmission Owner, and Distribution Provider shall apply

settings that are in accordance with PRC‐025‐12 – Attachment 1: Relay Settings, on each load‐responsive protective relay while maintaining reliable fault protection. [Violation Risk Factor: High] [Time Horizon: Long‐Term Planning]

M1. For each load‐responsive protective relay, each Generator Owner, Transmission Owner, and Distribution Provider shall have evidence (e.g., summaries of calculations, spreadsheets, simulation reports, or setting sheets) that settings were applied in accordance with PRC‐025‐12 – Attachment 1: Relay Settings.

C. Compliance

2 Interim Report: Causes of the August 14th Blackout in the United States and Canada, U.S.‐Canada Power System Outage Task Force, November 2003 (http://www.nerc.com/docs/docs/blackout/814BlackoutReport.pdf)


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8. Compliance Monitoring Process

8.1. Compliance Enforcement Authority

As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority” means NERC or the Regional Entity in their respective roles of monitoring and enforcing compliance with the NERC Reliability Standards.

8.2. Evidence Retention

The following evidence retention periods identify the period of time an entity is required to retain specific evidence to demonstrate compliance. For instances where the evidence retention period specified below is shorter than the time since the last audit, the Compliance Enforcement Authority (CEA) may ask an entity to provide other evidence to show that it was compliant for the full time period since the last audit.

The Generator Owner, Transmission Owner, and Distribution Provider shall keep data or evidence to show compliance as identified below unless directed by its CEA to retain specific evidence for a longer period of time as part of an investigation:

The Generator Owner, Transmission Owner, and Distribution Provider shall retain evidence of Requirement R1 and Measure M1 for the most recent three calendar years.

If a Generator Owner, Transmission Owner, or Distribution Provider is found non‐compliant, it shall keep information related to the non‐compliance until mitigation is complete and approved or for the time specified above, whichever is longer.

The CEA shall keep the last audit records and all requested and submitted subsequent audit records.

8.3. Compliance Monitoring and Assessment Processes

Compliance Audit

Self‐Certification

Spot Checking

Compliance Investigation

Self‐Reporting

Complaint

8.4. Additional Compliance Information

None


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Table of Compliance Elements .


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R # Time Horizon VRF



R1 Long‐Term

Planning High N/A N/A N/A

The Generator Owner, Transmission Owner, and Distribution Provider did not apply settings in accordance with PRC‐025‐12 – Attachment 1: Relay Settings, on an applied load‐responsive protective relay.

D. Regional Variances None.

E. Interpretations

F.E. Associated Documents NERC System Protection and Control Subcommittee, July 2010, ““Considerations for Power Plant and Transmission System Protection Coordination.”,” technical reference document, Revision 2. (Date of Publication: July 2015)

IEEE C37.102‐2006, “IEEE Guide for AC Generator Protection.” (Date of Publication: 2006)


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IEEE C37.17‐2012, “IEEE Standard for Trip Systems for Low‐Voltage (1000 V and below) AC and General Purpose (1500 V and below) DC Power Circuit Breakers.” (Date of Publication: September 18, 2012)

IEEE C37.2‐2008, “IEEE Standard for Electrical Power System Device Function Numbers, Acronyms, and Contact Designations.” (Date of Publication: October 3, 2008)


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Version History


1 August 15, 2013

Adopted by NERC Board of Trustees New

1 July 17, 2014 FERC order issued approving PRC‐025‐1


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PRC-025-12 April 19, 2017 SAR accepted by Standards Committee Revision

2 Adopted by NERC Board of Trustees

2 FERC order issued approving PRC‐025‐2


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PRC-025-2 – Attachment 1: Relay Settings

Introduction This standard does not require the Generator Owner, Transmission Owner, or Distribution Provider to use any of the protective functions listed in Table 1. Each Generator Owner, Transmission Owner, and Distribution Provider that applies load‐responsive protective relays on their respective Elements listed in 3.2, Facilities, shall use one of the following Options in Table 1, Relay Loadability Evaluation Criteria (“Table 1”), to set each load‐responsive protective relay element according to its application and relay type. The bus voltage is based on the criteria for the various applications listed in Table 1. Generators Synchronous generator relay pickup setting criteria values are derived from the unit’s maximum gross Real Power capability, in megawatts (MW), as reported to the Transmission Planner, and the unit’s Reactive Power capability, in megavoltampere‐reactive (Mvar), is determined by calculating the MW value based on the unit’s nameplate megavoltampere (MVA) rating at rated power factor. If different seasonal capabilities are reported, the maximum capability shall be used for the purposes of this standard as a minimum requirement. The Generator Owner may base settings on a capability that is higher than what is reported to the Transmission Planner. Asynchronous generator relay pickup setting criteria values (including inverter‐based installations) are derived from the site’s aggregate maximum complex power capability, in MVA, as reported to the Transmission Planner, including the Mvar output of any static or dynamic reactive power devices. If different seasonal capabilities are reported, the maximum capability shall be used for the purposes of this standard as a minimum requirement. The Generator Owner may base settings on a capability that is higher than what is reported to the Transmission Planner. For the application caseapplications where synchronous and asynchronous generator types are combined on a generator step‐up transformer or on Elements that connect the generator step‐up (GSU) transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant (Elements may also supply generating plant loads.),), the pickup setting criteria shall be determined by vector summing the pickup setting criteria of each generator type, and using the bus voltage for the given synchronous generator application and relay type. Transformers Calculations using the GSU transformer turns ratio shall use the actual tap that is applied (i.e., in service) for GSU transformers with deenergizedde‐energized tap changers (DETC). If load tap changers (LTC) are used, the calculations shall reflect the tap that results in the lowest generator bus voltage. When the criterion specifies the use of the GSU transformer’s impedance, the nameplate impedance at the nominal GSU transformer turns ratio shall be used. Applications that use more complex topology, such as generators connected to a multiple winding transformer, are not directly addressed by the criteria in Table 1. These topologies can result in complex power flows, and may require simulation to avoid overly conservative


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assumptions to simplify the calculations. Entities with these topologies should set their relays in such a way that they do not operate for the conditions being addressed in this standard. Multiple Lines Applications that use more complex topology, such as multiple lines that connect the generator step‐up (GSU) transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant (Elements may also supply generating plant loads) are not directly addressed by the criteria in Table 1. These topologies can result in complex power flows, and it may require simulation to avoid overly conservative assumptions to simplify the calculations. Entities with these topologies should set their relays in such a way that they do not operate for the conditions being addressed in this standard. Exclusions The following protection systems are excluded from the requirements of this standard:

1. Any relay elements that are in service only during start up. 2. Load‐responsive protective relay elements that are armed only when the generator is

disconnected from the system, (e.g., non‐directional overcurrent elements used in conjunction with inadvertent energization schemes, and open breaker flashover schemes).

3. Phase fault detector relay elements employed to supervise other load‐responsive phase distance elements (e.g., in order to prevent false operation in the event of a loss of potential) provided the distance element is set in accordance with the criteria outlined in the standard.

4. Protective relay elements that are only enabled when other protection elements fail (e.g., overcurrent elements that are only enabled during loss of potential conditions).

5. Protective relay elements used only for Special Protection SystemsRemedial Action Schemes that are subject to one or more requirements in a NERC or Regional Reliability Standard.

6. Protection systems that detect generator overloads that are designed to coordinate with the generator short time capability by utilizing an extremely inverse characteristic set to operate no faster than 7 seconds at 218% of fullloadfull load current (e.g., rated armature current), and prevent operation below 115% of full‐load current.3

7. Protection systems that detect transformer overloads and are designed only to respond in time periods which allow an operator 15 minutes or greater to respond to overload conditions.

Table 1 Table 1 beginning on the next pagebelow is structured and formatted to aid the reader with identifying an option for a given load‐responsive protective relay. The first column identifies the application (e.g., synchronous or asynchronous generators, generator step‐up transformers, unit auxiliary transformers, Elements that connect the GSU 3 IEEE C37.102‐2006, “Guide for AC Generator Protection,” Section 4.1.1.2.


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transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. Elements may also supply generating plant loads).). Dark blue horizontal bars, excluding the header which repeats at the top of each page, demarcate the various applications. The second column identifies the load‐responsive distance or overcurrent protective relay by IEEE device numbers (e.g., 21, 50, 51, 51V‐C, 51V‐R, or 67) according to the applied application in the first column. This also includes manufacture protective device trip unit designations for long‐time delay, short‐time delay, and instantaneous (e.g., L, S, and I). A light blue horizontal bar between the relay types is the demarcation between relay types for a given application. These light blue bars will contain no text., except when the same application continues on the next page of the table with a different relay type. The third column uses numeric and alphabetic options (i.e., index numbering) to identify the available options for setting load‐responsive protective relays according to the application and applied relay type. Another, shorter, light blue bar contains the word “OR,” and reveals to the reader that the relay for that application has one or more options (i.e., “ways”) to determine the bus voltage and pickup setting criteria in the fourth and fifth column, respectively. The bus voltage column and pickup setting criteria columns provide the criteria for determining an appropriate setting. The table is further formatted by shading groups of relays associated with asynchronous generator applications. Synchronous generator applications and the unit auxiliary transformer applications are not shaded. Also, intentional buffers were added to the table such that similar options, as possible, would be paired together on a per page basis. Note that some applications may have an additional pairing that might occur on adjacent pages.


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Application Relay Type Option Bus Voltage4 Pickup Setting Criteria

Synchronous generating unit(s), orincluding Elements utilized in the aggregation of dispersed power producing resources


1a



OR

1b



OR

1c


The impedance element shall be set less than the calculated impedance derived from 115% of: (1) Real Power output – 100% of the gross MW capability reported to the Transmission Planner, and (2) Reactive Power output –100% of the maximum gross Mvar output during field‐forcing as determined by simulation


4 Calculations using the generator step‐up (GSU) transformer turns ratio shall use the actual tap that is applied (i.e., in service) for GSU transformers with deenergized tap changers (DETC). If load tap changers (LTC) are used, the calculations shall reflect the tap that results in the lowest generator bus voltage. When the criterion specifies the use of the GSU transformer’s impedance, the nameplate impedance at the nominal GSU turns ratio shall be used.


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Synchronous generating unit(s), orincluding Elements utilized in the aggregation of dispersed power producing resources

Phase time overcurrent relay (e.g., 50, 51), or (51V‐R) – voltage‐restrained)

2a



OR

2b



OR

2c


The overcurrent element shall be set greater than 115% of the calculated current derived from: (1) Real Power output – 100% of the gross MW capability reported to the Transmission Planner or, and (2) Reactive Power output –100% of the maximum gross Mvar output during field‐forcing as determined by simulation

The same application continues with a different relay type belowPhase time overcurrent relay (e.g., 51V‐C) – voltage controlled (Enabled to operate as a function of voltage)

3





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Asynchronous generating unit(s) (including inverter‐based installations), orincluding Elements utilized in the aggregation of dispersed power producing resources


4



Phase time overcurrent relay (e.g., 50, 51), or (51V‐R) – voltage‐restrained)

55a



OR

5b


The overcurrent element shall not infringe upon the resource capability (including the Mvar output of the resource and any static or dynamic reactive power devices) with worst case documented tolerances applied between the maximum resource capability and the overcurrent element (see Figure A).


6





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Phase distance relay (e.g., 21) – directional toward the Transmission system – installed on generator‐side of the GSU transformer

If the relay is installed on the high-side of the GSU transformer use Option 14 5

7a



OR

7b



OR

7c






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Phase time overcurrent relay (e.g., 50 or 51) – installed on generator‐side of the GSU transformer


8a



OR

8b



OR

8c






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Phase directional time overcurrent relay (e.g., 67) – directional toward the Transmission system – installed on generator‐side of the GSU transformer


9a



OR

9b



OR

9c






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Generator step‐up transformer(s) connected to asynchronous generators only (including inverter‐based installations)

Phase distance relay (e.g., 21) – directional toward the Transmission system – installed on generator‐side of the GSU transformer

If the relay is installed on the high-side of the GSU transformer use Option 178

10



Phase time overcurrent relay (e.g., 50 or 51) – installed on generator‐side of the GSU transformer


11

Generator bus voltage corresponding to 1.0 per unit of the high‐side nominal voltage times the turns ratio of the generator step‐up transformer for overcurrent relays installed on the low‐side



8 If the relay is installed on the high‐side of the GSU transformer use Option 17. 9 If the relay is installed on the high‐side of the GSU transformer use Option 18.


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Phase directional time overcurrent relay (e.g., 67) – directional toward the Transmission system – installed on generator‐side of the GSU transformer


12



A different application starts belowon the next page

Unit auxiliary transformer(s) (UAT)

Phase time overcurrent relay (e.g., 50 or 51) applied at the high‐side terminals of the UAT, for which operation of the relay will cause the associated generator to trip.

13a 1.0 per unit of the winding nominal voltage of the unit auxiliary transformer

The overcurrent element shall be set greater than 150% of the calculated current derived from the unit auxiliary transformer maximum nameplate MVA rating

OR

13b Unit auxiliary transformer bus voltage corresponding to the measured current

The overcurrent element shall be set greater than 150% of the unit auxiliary transformer measured current at the generator maximum gross MW capability reported to the Transmission Planner




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Elements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. (Elements may also supply generating plant loads. –) – connected to synchronous generators

Phase distance relay (e.g., 21) – directional toward the Transmission system – installed on the high‐side of the GSU transformer

If the relay is installed and on the generator-sideremote end of the GSU transformer use Option 7line11



OR

14b

Simulated line voltage coincident with the highest Reactive Power output achieved during field-forcing in response to a 0.85 per unit nominal voltage on the high-side terminals of the generator step-up transformer prior to field-forcing

The impedance element shall be set less than the calculated impedance derived from 115% of:

(1) Real Power output – 100% of the aggregate generation gross MW reported to the Transmission Planner, and

(2) Reactive Power output –100% of the aggregate generation maximum gross Mvar output during field-forcing as determined by simulation




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Elements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. Elements may also supply generating plant loads. –connected to synchronous generators

Phase overcurrent supervisory element (50) – associated with current-based, communication-assisted schemes where the scheme is capable of tripping for loss of communications installed on the high-side of the GSU transformer or phase time overcurrent relay (51) – installed on the high-side of the GSU transformer

If the relay is installed on the generator-side of the GSU transformer use Option 8

15a 0.85 per unit of the line nominal voltage

The overcurrent element shall be set greater than 115% of the calculated current derived from:

(1) Real Power output – 100% of the aggregate generation gross MW reported to the Transmission Planner, and

(2) Reactive Power output – 120% of the aggregate generation MW value, derived from the generator nameplate MVA rating at rated power factor

OR

15b14b

Simulated line voltage coincident with the highest Reactive Power output achieved during field‐forcing in response to a 0.85 per unit of the line nominal voltage onat the high-side terminalsremote end of the generator step-up transformerline prior to field‐forcing

The overcurrentimpedance element shall be set greaterless than 115% of the calculated currentimpedance derived from 115% of: (1) Real Power output – 100% of the aggregate generation gross MW reported to the Transmission Planner, and (2) Reactive Power output –100% of the aggregate generation maximum gross Mvar output during field‐forcing as determined by simulation


Elements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit

Phase directionalinstantaneous overcurrent supervisory element (67e.g., 50) – associated with current‐based, communication‐

16a15a 0.85 per unit of the line nominal voltage at the relay location


OR


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or generating plant. (Elements may also supply generating plant load. –loads) – connected to synchronous generators

assisted schemes where the scheme is capable of tripping for loss of communications directional toward the Transmission system installed on the high‐side of the GSU transformer and remote end of the line and/or phase directional time overcurrent relay (67) – directional toward the Transmission systeme.g., 51) – installed on the high‐side of the GSU transformer

If the relay is installed on the generator-side of the GSU transformer use Option 9and remote end of the line12

15b






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Elements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant (Elements may also supply generating plant load.) –connected to synchronous generators

Phase directional instantaneous overcurrent supervisory element (e.g., 67) – associated with current‐based, communication‐assisted schemes where the scheme is capable of tripping for loss of communications directional toward the Transmission system installed on the high‐side of the GSU transformer and remote end of the line and/or phase directional time overcurrent relay (e.g., 67) – directional toward the Transmission system installed on the high‐side of the GSU transformer and remote end of the line13



OR

16b

Simulated line voltage coincident with the highest Reactive Power output achieved during field‐forcing in response to a 0.85 per unit of the line nominal voltage onat the high-side terminalsremote end of the generator step-up transformerline prior to field‐forcing


A different application starts on the next page 13 If the relay is installed on the generator‐side of the GSU transformer use Option 9.


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Elements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. (Elements may also supply generating plant loads.) –connected to asynchronous generators only (including inverter‐based installations)

Phase distance relay (e.g., 21) – directional toward the Transmission system– installed on the high‐side of the GSU transformer

If the relay is installed and on the generator-sideremote end of the GSU transformer use Option 10line14





tor Relay Loadability

bility Evaluation Criteria

Relay Type Option Bus Voltage4 Pickup Setting Criteria

se antaneous rcurrent ervisory element , 50) – ciated with ent‐based, munication‐sted schemes re the scheme pable of ping for loss of munications alled on the ‐side of the GSU sformer and on remote end of ine and/or se time rcurrent relay , 51) – installed he high‐side of GSU sformer

e relay is alled on the erator-side of on the GSU sformer use on 11remote of the line15




bility Evaluation Criteria

Relay Type Option Bus Voltage4 Pickup Setting Criteria



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Elements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. (Elements may also supply generating plant loads.) –connected to asynchronous generators only (including inverter‐based installations)

Phase directional instantaneous overcurrent supervisory element (e.g., 67) – associated with current‐based, communication‐assisted schemes where the scheme is capable of tripping for loss of communications directional toward the Transmission system installed on the high‐side of the GSU transformer and on the remote end of the line and/or Phase directional time overcurrent relay (e.g., 67) – installed on the high‐side of the GSU transformer

If the relay is installed on the generator-side of and on the GSU transformer use Option 12remote end of the line16



End of Table 1


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Figure A. This figure is for demonstration of Option 5b and does not mandate a specific type of protective curve or device manufacturer.


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PRC-025-12 Guidelines and Technical Basis

Introduction The document, “Considerations for Power Plant and Transmission System Protection Coordination,” published by the NERC System Protection and Control Subcommittee (SPCS) provides extensive general discussion about the protective functions and generator performance addressed within this standard. This document was last revised in July 20102015.17 The basis for the standard’s loadability criteria for relays applied at the generator terminals or low‐side of the generator step‐up (GSU) transformer is the dynamic generating unit loading values observed during the August 14, 2003 blackout, other subsequent system events, and simulations of generating unit response to similar system conditions. The Reactive Power output observed during field‐forcing in these events and simulations approaches a value equal to 150 percent of the Real Power (MW) capability of the generating unit when the generator is operating at its Real Power capability. In the SPCS technical reference document, two operating conditions were examined based on these events and simulations: (1) when the unit is operating at rated Real Power in MW with a level of Reactive Power output in Mvar which is equivalent to 150 percent times the rated MW value (representing some level of field‐forcing) and (2) when the unit is operating at its declared low active Real Power operating limit (e.g., 40 percent of rated Real Power) with a level of Reactive Power output in Mvar which is equivalent to 175 percent times the rated MW value (representing some additional level of field‐forcing). Both conditions noted above are evaluated with the GSU transformer high‐side voltage at 0.85 per unit. These load operating points are believed to be conservatively high levels of Reactive Power out of the generator with a 0.85 per unit high‐side voltage which was based on these observations. However, for the purposes of this standard it was determined that the second load point (40 percent) offered no additional benefit and only increased the complexity for an entity to determine how to comply with the standard. Given the conservative nature of the criteria, which may not be achievable by all generating units, an alternate method is provided to determine the Reactive Power output by simulation. Also, to account for Reactive Power losses in the GSU transformer, a reduced level of output of 120 percent times the rated MW value is provided for relays applied at the high‐side of the GSU transformer and on Elements that connect a GSU transformer to the Transmission system and are used exclusively to export energy directly from a BES generating unit or generating plant. The phrase, “while maintaining reliable fault protection” in Requirement R1, describes that the Generator Owner, Transmission Owner, and Distribution Provider is to comply with this standard while achieving its desired protection goals. Load‐responsive protective relays, as addressed within this standard, may be intended to provide a variety of backup protection functions, both within the generating unit or generating plant and on the Transmission system, and this standard 17 http://www.nerc.com/docs/pc/spctf/Gen%20Prot%20Coord%20Rev1%20Final%2007-30-2010.pdf http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%2020/SPCS%20 Gen%20Prot%20Coordination%20Technical%20Reference%20Document.pdf


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is not intended to result in the loss of these protection functions. Instead, it is suggested that the Generator Owner, Transmission Owner, and Distribution Provider consider both the requirement within this standard and its desired protection goals, and perform modifications to its protective relays or protection philosophies as necessary to achieve both. For example, if the intended protection purpose is to provide backup protection for a failed Transmission breaker, it may not be possible to achieve this purpose while complying with this standard if a simple mho relay is being used. In this case, it may be possible to meet this purpose by replacing the legacy relay with a modern advanced‐technology relay that can be set using functions such as load encroachment. It may otherwise be necessary to reconsider whether this is an appropriate method of achieving protection for the failed Transmission breaker, and whether this protection can be better provided by, for example, applying a breaker failure relay with a transfer trip system. Requirement R1 establishes that the Generator Owner, Transmission Owner, and Distribution Provider must understand the applications of Attachment 1: Relay Settings, Table 1: Relay Loadability Evaluation Criteria (“Table 1”) in determining the settings that it must apply to each of its load‐responsive protective relays to prevent an unnecessary trip of its generator during the system conditions anticipated by this standard. Applicability To achieve the reliability objective of this standard it is necessary to include all load‐responsive protective relays that are affected by increased generator output in response to system disturbances. This standard is therefore applicable to relays applied by the Generator Owner, Transmission Owner, and Distribution Provider at the terminals of the generator, GSU transformer, unit auxiliary transformer (UAT), Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant, and Elements utilized in the aggregation of dispersed power producing resources. The Generator Owner’s interconnection facility (in some cases labeled a “transmission Facility” or “generator leads”) consists of Elements between the GSU transformer and the interface with the portion of the Bulk Electric System (BES) where Transmission Owners take over the ownership. This standard does not use the industry recognized term “generator interconnection Facility” consistent with the work of Project 2010‐07 (Generator Requirements at the Transmission Interface), because the term generator interconnection Facility implies ownership by the Generator Owner. Instead, this standard refers to these Facilities as “Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant” to include these Facilities when they are also owned by the Transmission Owner or Distribution Provider. The load‐responsive protective relays in this standard for which an entity shall be in compliance is dependent on the location and the application of the protective functions. Figures 1, 2, and 3 illustrate various generator interface connections with the Transmission system.


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Figure 1 Figure 1 is a single (or set) of generators connected to the Transmission system through a radial line that is used exclusively to export energy directly from a BES generating unit or generating plant to the network. The protective relay R1 located on the high‐side of the GSU transformer breaker CB100 is generally applied to provide backup protection to the relaying located at Bus A and in some cases Bus B. Under this application, relay R1 would apply the loadability requirement in PRC‐025‐12 using an appropriate option for the application from Table 1 (e.g., Options 14 through 19) for Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. The protective relay R2 located on the incoming source breaker CB102 to the generating plant applies relaying that primarily protects the line by using line differential relaying from Bus A to B and also provides backup protection to the transmission relaying at Bus B. In this case, the relay function that provides line protection would apply the loadability requirement in PRC‐025‐12 and an appropriate option for the application from Table 1 (e.g., 15a, 15b, 16a, 16b, 18, and 19) for phase overcurrent supervisory elements (i.e., phase fault detectors) associated with current‐based, communication‐assisted schemes (i.e., pilot wire, phase comparison, and line current differential) where the scheme is capable of tripping for loss of communications. The backup protective function would apply the requirement in the PRC‐025‐12 standard using an appropriate option for the application from Table 1 (e.g., Options 14 through 19) for Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. Since Elements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant are applicable to the standard, the loadability for relays applied on these Elements as shown in the shaded area of Figure 1 (i.e., CB102 and CB103) must be considered. If relay R2 or R3 is set with an element directional toward the transmission system (e.g., Buses B, C and D) or are non‐directional, the relay would be affected by increased generator output in response to system disturbances and must meet the loadability setting criteria described in the standard. If relay R2 or R3 is set with an element directional toward the generator (e.g., Bus A), the relay would not be affected by increased generator output in response to system disturbances; therefore, the entity would not be required to apply the loadability setting criteria described in this standard.

In this particular case, the applicable responsible entity’s directional relay R3 located on breaker CB103 at Bus B looking toward Bus A (i.e., generation plant) is not included in either loadability standard (i.e., PRC-023 or PRC-025) since it is not affected by increased generator output in response to system disturbances described in this standard or by increased transmission system loading described in PRC-023. Any protective element set to protect in the direction from Bus A to B is included within the PRC-025-1 standard. PRC-025-1 is applicable to Relay R3, for example, if the relay is applied and set to trip for a reverse element directional toward the Transmission system.


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Figure 1. Generation exported through a single radial line.

Figure 2 Figure 2 is an example of a single (or set) of generators connected to the Transmission system through multiple lines that are used exclusively to export energy directly from a BES generating unit or generating plant to the network. The protective relay R1 on the high‐side of the GSU transformer breaker CB100 is generally applied to provide backup protection to the Transmission relaying located at Bus A and in some cases Bus B. Under this application, relay R1 would apply the loadability requirement in PRC‐025‐12 using an appropriate option for the application from Table 1 (e.g., Options 14 through 19) for Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. The protective relays R2 and R3 located on the incoming source breakers CB102 and CB103 to the generating plant applies relaying that primarily protects the line from Bus A to B and also provides backup protection to the transmission relaying at Bus B. In this case, the relay function that provides line protection would apply the loadability requirement in PRC‐025‐12 and an appropriate option for the application from Table 1 (e.g., Options 15a, 15b, 16a, 16b, 18, and 19) for phase overcurrent supervisory elements (i.e., phase fault detectors) associated with current‐based, communication‐assisted schemes (i.e., pilot wire, phase comparison, and line current


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differential) where the scheme is capable of tripping for loss of communications. The backup protective function would apply the requirement in the PRC‐025‐12 standard using an appropriate option for the application from Table 1 (e.g., Options 14 through 19) for Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. In this particular case, the applicable responsible entity’s directional relay R4 and R5 located on the breakers CB104 and CB105, respectively at Bus B looking into the generation plant are not included in either loadability standard (i.e., PRC-023 or PRC-025) since they are not subject to the stressed loading requirements described in the standard or by increased transmission system loading described in PRC-023. Any protective element set to protect in the direction from Bus A to B is included within the PRC-025-1 standard. PRC-025-1 is applicable to Relay R4 and R5, for example, if the relays are applied and set to trip for a reverse element directional toward the Transmission system.

Since Elements that connect the GSU transformer(s) to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant are applicable to the standard, the loadability for relays applied on these Elements as shown in the shaded area of Figure 2 (i.e., CB102, CB103, CB104, and CB105) must be considered. If relay R2, R3, R4, or R5 is set with an element directional toward the transmission system (e.g., Buses B, C and D) or are non‐directional, the relay would be affected by increased generator output in response to system disturbances and must meet the loadability setting criteria described in the standard. If relay R2, R3, R4, or R5 is set with an element directional toward the generator (e.g., Bus A), the relay would not be affected by increased generator output in response to system disturbances; therefore, the entity would not be required to apply the loadability setting criteria described in this standard.


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Figure 2. Generation exported through multiple radial lines.

Figure 3 Figure 3 is example a single (or set) of generators exporting power dispersed through multiple lines to the Transmission system through a network. The protective relay R1 on the high‐side of the GSU transformer breaker CB100 is generally applied to provide backup protection to the Transmission relaying located at Bus A and in some cases Bus C or Bus D. Under this application, relay R1 would apply the applicable loadability requirement in PRC‐025‐12 using an appropriate option for the application from Table 1 (e.g., Options 14 through 19) for Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. Since the lines from Bus A to Bus C and from Bus A to Bus D are part of the transmission network, these lines would not be considered as Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. Therefore, the applicable responsible entity would be responsible for the load‐responsive protective relays R2 and R3 under the PRC‐023 standard. The applicable responsible entity’s loadability relays R4 and R5 located on the breakers CB104 and CB105 at Bus C and D are also subject to the requirements of the PRC‐023 standard.


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Relays subject to PRC-025

CB101

CB100

GSU

UATBus A

CB102

Bus D

Bus C

R2

R1

CB103

R3

CB104

R4

R5

CB105

Figure 3. Generation exported through a network.

Elements utilized in the aggregation of dispersed power producing resources (in some cases referred to as a “collector system”) consist of the Elements between individual generating units and the common point of interconnection to the Transmission system. This standard is also applicable to the UATs that supply station service power to support the on‐line operation of generating units or generating plants. These transformers are variably referred to as station power, unit auxiliary transformer(s), or station service transformer(s) used to provide overall auxiliary power to the generator station when the generator is running. Inclusion of these transformers satisfies a directive in FERC Order No. 733, paragraph 104, which directs NERC to include in this standard a loadability requirement for relays used for overload protection of the UAT(s) that supply normal station service for a generating unit. Synchronous Generator Performance When a synchronous generator experiences a depressed voltage, the generator will respond by increasing its Reactive Power output to support the generator terminal voltage. This operating condition, known as “field‐forcing,” results in the Reactive Power output exceeding the steady‐state capability of the generator and may result in operation of generation system load‐responsive protective relays if they are not set to consider this operating condition. The ability of


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the generating unit to withstand the increased Reactive Power output during field‐forcing is limited by the field winding thermal withstand capability. The excitation limiter will respond to begin reducing the level of field‐forcing in as little as one second, but may take much longer, depending on the level of field‐forcing given the characteristics and application of the excitation system. Since this time may be longer than the time‐delay of the generator load‐responsive protective relay, it is important to evaluate the loadability to prevent its operation for this condition. The generator bus voltage during field‐forcing will be higher than the high‐side voltage due to the voltage drop across the GSU transformer. When the relay voltage is supplied from the generator bus, it is necessary to assess loadability using the generator bus voltage. The criteria established within Table 1 are based on 0.85 per unit of Transmission systemthe line nominal voltage. This voltage was widely observed during the events of August 14, 2003, and was determined during the analysis of the events to represent a condition from which the System may have recovered, had not other undesired behavior not occurred. The dynamic load levels specified in Table 1 under column “Pickup Setting Criteria” are representative of the maximum expected apparent power during field‐forcing with the Transmission system voltage at 0.85 per unit, for example, at the high‐side of the GSU transformer. These values are based on records from the events leading to the August 14, 2003 blackout, other subsequent System events, and simulations of generating unit responses to similar conditions. Based on these observations, the specified criteria represent conservative but achievable levels of Reactive Power output of the generator with a 0.85 per unit high‐side voltage at the point of interconnection. The dynamic load levels were validated by simulating the response of synchronous generating units to depressed Transmission system voltages for 67 different generating units. The generating units selected for the simulations represented a broad range of generating unit and excitation system characteristics as well as a range of Transmission system interconnection characteristics. The simulations confirmed, for units operating at or near the maximum Real Power output, that it is possible to achieve a Reactive Power output of 1.5 times the rated Real Power output when the Transmission system voltage is depressed to 0.85 per unit. While the simulations demonstrated that all generating units may not be capable of this level of Reactive Power output, the simulations confirmed that approximately 20 percent of the units modeled in the simulations could achieve these levels. On the basis of these levels, Table 1, Options 1a (i.e., 0.95 per unit) and 1b (i.e., 0.85 per unit), for example, are based on relatively simple, but conservative calculations of the high‐side nominal voltage. In recognition that not all units are capable of achieving this level of output Option 1c (i.e., simulation) was developed to allow the Generator Owner, Transmission Owner, or Distribution Provider to simulate the output of a generating unit when the simple calculation is not adequate to achieve the desired protective relay setting. Dispersed Generation This standard is applicable to dispersed generation such as wind farms and solar arrays. The intent of this standard is to ensure the aggregate facility as defined above will remain on‐line


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during a system disturbance; therefore, all output load‐responsive protective elementsrelays associated with the facility are included in PRC ‐025. Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed primarily for aggregating capacity, connected at a common point at a voltage of 100 kV or above are included in PRC‐025‐12. Load‐responsive protective relays that are applied on Elements that connect these individual generating units through the point of interconnection with the Transmission system are within the scope of PRC‐025‐12. For example, feeder overcurrent relays and feeder step‐up transformer overcurrent relays (see Figure 5) are included because these relays are challenged by generator loadability. In the case of solar arrays where there are multiple voltages utilized in converting the solar panel DC output to a 60Hz AC waveform, the “terminal” is defined at the 60Hz AC output of the inverter‐solar panel combination. Asynchronous Generator Performance Asynchronous generators, however, do not have excitation systems and will not respond to a disturbance with the same magnitude of apparent power that a synchronous generator will respond. Asynchronous generators, though, will support the system during a disturbance. Inverter‐based generators will provide Real Power and Reactive Power (depending on the installed capability and regional grid code requirements) and may even provide a faster Reactive Power response than a synchronous generator. The magnitude of this response may slightly exceed the steady‐state capability of the inverter but only for a short duration before a crowbar functionlimiter functions will activate. Although induction generators will not inherently supply Reactive Power, induction generator installations may include static and/or dynamic reactive devices, depending on regional grid code requirements. These devices also may provide Real Power during a voltage disturbance. Thus, tripping asynchronous generators may exacerbate a disturbance. Inverters, including wind turbines (i.e., Types 3 and 4) and photovoltaic solar, are commonly available with 0.90 power factor capability. This calculates to an apparent power magnitude of 1.11 per unit of rated MW. Similarly, induction generator installations, including Type 1 and Type 2 wind turbines, often include static and/or dynamic reactive devices to meet grid code requirements and may have apparent power output similar to inverter‐based installations; therefore, it is appropriate to use the criteria established in the Table 1 (i.e., Options 4, 5, 6, 10, 11, 12, 17, 18, and 19) for asynchronous generator installations. Synchronous Generator Simulation Criteria The Generator Owner, Transmission Owner, or Distribution Provider who elects a simulation option to determine the synchronous generator performance on which to base relay settings may simulate the response of a generator by lowering the Transmission system voltage onat the


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remote end of the line or at the high‐side of the GSU transformer. (as prescribed by the Table 1 criteria). This can be simulated by means such as modeling the connection of a shunt reactor onat the Transmission system to lowerremote end of the line or at the GSU transformer high‐side to lower the voltage to 0.85 per unit prior to field‐forcing. The resulting step change in voltage is similar to the sudden voltage depression observed in parts of the Transmission system on August 14, 2003. The initial condition for the simulation should represent the generator at 100 percent of the maximum gross Real Power capability in MW as reported to the Transmission Planner. The simulation is used to determine the Reactive Power and voltage to be used to calculate relay pickup setting limits. The Reactive Power value obtained by simulation is the highest simulated level of Reactive Power achieved during field‐forcing. The voltage value obtained by simulation is the simulated voltage coincident with the highest Reactive Power achieved during field‐forcing. These values of Reactive Power and voltage correspond to the minimum apparent impedance and maximum current observed during field‐forcing. Phase Distance Relay – Directional Toward Transmission System (e.g., 21) Generator phase distance relays that are directional toward the Transmission system, whether applied for the purpose of primary or backup GSU transformer protection, external system backup protection, or both, were noted during analysis of the August 14, 2003 disturbance event to have unnecessarily or prematurely tripped a number of generating units or generating plants, contributingwhich contributed to the scope of that disturbance. Specifically, eight generators are known to have been tripped by this protection function. These options establish criteria for phase distance relays that are directional toward the Transmission system to help assure that generators, to the degree possible, will provide System support during disturbances in an effort to minimize the scope of those disturbances. The phase distance relay that is directional toward the Transmission system measures impedance derived from the quotient of generator terminal voltage divided by generator stator current. Section 4.6.1.1 of IEEE C37.102‐2006, “Guide for AC Generator Protection,” describes the purpose of this protection as follows (emphasis added):

“The distance relay applied for this function is intended to isolate the generator from the power system for a fault that is not cleared by the transmission line breakers. In some cases this relay is set with a very long reach. A condition that causes the generator voltage regulator to boost generator excitation for a sustained period may result in the system apparent impedance, as monitored at the generator terminals, to fall within the operating characteristics of the distance relay. Generally, a distance relay setting of 150% to 200% of the generator MVA rating at its rated power factor has been shown to provide good coordination for stable swings, system faults involving in‐feed, and normal loading conditions. However, this setting may also result in failure of the relay to operate for some line faults where the line relays fail to


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clear. It is recommended that the setting of these relays be evaluated between the generator protection engineers and the system protection engineers to optimize coordination while still protecting the turbine generator. Stability studies may be needed to help determine a set point to optimize protection and coordination. Modern excitation control systems include overexcitation limiting and protection devices to protect the generator field, but the time delay before they reduce excitation is several seconds. In distance relay applications for which the voltage regulator action could cause an incorrect trip, consideration should be given to reducing the reach of the relay and/or coordinating the tripping time delay with the time delays of the protective devices in the voltage regulator. Digital multifunction relays equipped with load encroachment binders [sic] can prevent misoperation for these conditions. Within its operating zone, the tripping time for this relay must coordinate with the longest time delay for the phase distance relays on the transmission lines connected to the generating substation bus. With the advent of multifunction generator protection relays, it is becoming more common to use two‐phase distance zones. In this case, the second zone would be set as previously described. When two zones are applied for backup protection, the first zone is typically set to see the substation bus (120% of the GSU transformer). This setting should be checked for coordination with the zone‐1 element on the shortest line off of the bus. The normal zone‐2 time‐delay criteria would be used to set the delay for this element. Alternatively, zone‐1 can be used to provide high‐speed protection for phase faults, in addition to the normal differential protection, in the generator and iso‐phase bus with partial coverage of the GSU transformer. For this application, the element would typically be set to 50% of the transformer impedance with little or no intentional time delay. It should be noted that it is possible that this element can operate on an out‐of‐step power swing condition and provide misleading targeting.”

If a mho phase distance relay that is directional toward the Transmission system cannot be set to maintain reliable fault protection and also meet the criteria in accordance with Table 1, there may be other methods available to do both, such as application of blinders to the existing relays, implementation of lenticular characteristic relays, application of offset mho relays, or implementation of load encroachment characteristics. Some methods are better suited to improving loadability around a specific operating point, while others improve loadability for a wider area of potential operating points in the R‐X plane. The operating point for a stressed System condition can vary due to the pre‐event system conditions, severity of the initiating event, and generator characteristics such as Reactive Power capability.


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For this reason, it is important to consider the potential implications of revising the shape of the relay characteristic to obtain a longer relay reach, as this practice may result in a relay characteristic that overlaps the capability of the generating unit when operating at a Real Power output level other than 100 percent of the maximum Real Power capability. Overlap of the relay characteristic and generator capability could result in tripping the generating unit for a loading condition within the generating unit capability. The examples in Appendix E of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document illustrate the potential for, and need to avoid, encroaching on the generating unit capability. Phase Instantaneous Overcurrent Relay (e.g., 50) The 50 element is a non‐directional overcurrent element that typically has no intentional time delay. The primary application is for close‐in high current faults where high speed operation is required or preferred. The instantaneous overcurrent elements are subject to the same loadability issues as the time overcurrent elements referenced in this standard. Phase Time Overcurrent Relay (e.g., 51) See section 3.9.Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document for a detailed discussion of this protection function. Note that the Table 1 setting criteria established within the Table 1 options differdiffers from section 3.9.2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Rather than establishing a uniform setting threshold of 200 percent of the generator MVA rating at rated power factor for all applications, the Table 1 setting criteria are based on the maximum expected generator Real Power output based on whether the generator operatesis a synchronous or asynchronous unit. Phase Time Overcurrent Relay – Voltage-Restrained (e.g., 51V-R) Phase time overcurrent voltage‐restrained relays (e.g., 51V‐R), which change their sensitivity as a function of voltage, whether applied for the purpose of primary or backup GSU transformer protection, for external system phase backup protection, or both, were noted, during analysis of the August 14, 2003 disturbance event to have unnecessarily or prematurely tripped a number of generating units or generating plants, contributing to the scope of that disturbance. Specifically, 20 generators are known to have been tripped by voltage‐restrained and voltage‐controlled protection functions together. These protective functions are variably referred to by IEEE function numbers 51V, 51R, 51VR, 51V/R, 51V‐R, or other terms. See section 3.10 of the Power Plant and Transmission System Protection Coordination technical reference document for a detailed discussion of this protection function.

Phase Time Overcurrent Relay – Voltage Controlled (51V-C) Phase time overcurrent voltage-controlled relays (51V-C), enabled as a function of voltage, are variably referred to by IEEE function numbers 51V, 51C, 51VC, 51V/C, 51V-C, or other terms. See section 3.10 of theSee Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document for a detailed discussion of this protection function.


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Phase Time Overcurrent Relay – Voltage Controlled (e.g., 51V-C) Phase time overcurrent voltage‐controlled relays (e.g., 51V‐C), enabled as a function of voltage, are variably referred to by IEEE function numbers 51V, 51C, 51VC, 51V/C, 51V‐C, or other terms. See Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document for a detailed discussion of this protection function. Phase Directional Time Overcurrent Relay – Directional Toward Transmission System (e.g., 67) See section 3.9.Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document for a detailed discussion of the phase time overcurrent protection function. The basis for setting directional and non‐directional time overcurrent relays is similar. Note that the Table 1settingsetting criteria established within the Table 1 options differdiffers from section 3.9.2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Rather than establishing a uniform setting threshold of 200 percent of the generator MVA rating at rated power factor for all applications, the Table 1 setting criteria are based on the maximum expected generator Real Power output based on whether the generator operatesis a synchronous or asynchronous unit.


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Table 1, Options

Introduction The margins in the Table 1 options are based on guidance found in the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. The generator bus voltage during field‐forcing will be higher than the high‐side voltage due to the voltage drop across the GSU transformer. When the relay voltage is supplied from the generator bus, it is necessary to assess loadability using the generator bus voltage. Relay Connections Figures 4 and 5 below illustrate the connections for each of the Table 1 options provided in PRC‐025‐12, Attachment 1: Relay Settings, Table 1: Relay Loadability Evaluation Criteria.

Figure 4. Relay Connection for corresponding synchronous options.


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To auxiliary loads

21TGSU

5000/5

5000/5

5000/5

200/1

To 345 kV system

51 V‐R51 V‐C

UAT

Aggregated MVA3‐40 MVA @ 0.85 pf1‐5 Mvar

50/51

21 50/51

67

Options 13a and 13b

Option 10

GSU Data150 MVA346.5 kV / 22 kVX = 12.14%

Option 12

Option 11

21

50/5167

Option 17

Option 19

2000/1

300/5

300/5

5000/521

51 V‐R51 V‐C

Option 18

50/51

Aggregated Mvar15 Mvar

50/51

22 kV / 12 kV

50/51

Option 5

Option 5

5 Mvar

5000/5

51 V‐R

51 V‐C

21

Options4, 5, & 6

Options4, 5, & 6

21

Figure 5. Relay Connection for corresponding asynchronous options including inverter‐based installations.

Synchronous Generators Phase Distance Relay – Directional Toward Transmission System (e.g., 21) (Options 1a, 1b, and 1c) Table 1, Options 1a, 1b, and 1c, are provided for assessing loadability for synchronous generators applying phase distance relays that are directional toward the Transmission system. These margins are based on guidance found in section 3.1Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Option 1a calculates a generator bus voltage corresponding to 0.95 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying athe 0.95 per unit nominal voltage, at the high‐side terminals of the GSU transformer times, by the GSU transformer turns ratio (excluding the impedance). This is the simplest


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calculation that approximatesis a straightforward way to approximate the stressed system conditions. Option 1b calculates the generator bus voltage corresponding to 0.85 per unit nominal voltage on the high‐side terminals of the GSU transformer. The voltage drop across the GSU transformer is calculated based on a 0.85 per unit nominal voltage at the high‐side terminals of the GSU transformer and accounts foras well as the turns ratio and impedance. The actual generator bus voltage may be higher depending on the GSU transformer impedance and the actual Reactive Power achieved. This calculation is a more involved, more in‐depth and precise method for setting of the impedance element than Option 1a. Option 1c simulates the generator bus voltage coincident with the highest Reactive Power output achieved during field‐forcing. This output is in response to a 0.85 per unit nominal voltage on the high‐side terminals of the GSU transformer prior to field‐forcing. Using simulation is a more involved, more precise setting of the impedance element overall. For Options 1a and 1b, the impedance element isshall be set less than the calculated impedance derived from 115percent115 percent of both: the Real Power output of 100 percent of the maximum gross MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 150 percent of the MW value, derived from the generator nameplate MVA rating at rated power factor. For Option 1c, the impedance element isshall be set less than the calculated impedance derived from 115 percent of both: the Real Power output of 100 percent of the maximum gross MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 100 percent of the maximum gross Mvar output during field‐forcing as determined by simulation. Synchronous Generators Phase Time Overcurrent Relay – (e.g., 50, 51, or 51V-R – Voltage- Restrained (51V-R) (Options 2a, 2b, and 2c) Table 1, Options 2a, 2b, and 2c, are provided for assessing loadability for synchronous generators applying phase time overcurrent relays (e.g., 50 or 51) or voltage‐restrained (e.g., 51V‐R) which change theirchanges its sensitivity as a function of voltage (“voltage‐restrained”). These margins are based on guidance found in section 3.10Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Option 2a calculates a generator bus voltage corresponding to 0.95 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying athe 0.95 per unit nominal voltage, at the high‐side terminals of the GSU transformer times, by the GSU transformer turns ratio (excluding the impedance). This is the simplest calculation that approximatesis a straightforward way to approximate the stressed system conditions. Option 2b calculates the generator bus voltage corresponding to 0.85 per unit nominal voltage on the high‐side terminals of the GSU transformer. The voltage drop across the GSU transformer


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is calculated based on a 0.85 per unit nominal voltage at the high‐side terminals of the GSU transformer and accountsas well as for the turns ratio and impedance. The actual generator bus voltage may be higher depending on the GSU transformer impedance and the actual Reactive Power achieved. This calculation is a more involved, morein‐depth and precise method for setting of the overcurrent element than Option 2a. Option 2c simulates the generator bus voltage coincident with the highest Reactive Power output achieved during field‐forcing. This output is in response to a 0.85 per unit nominal voltage on the high‐side terminals of the GSU transformer prior to field‐forcing. Using simulation is a more involved, more precise setting of the overcurrent element overall. For Options 2a and 2b, the overcurrent element isshall be set greater than 115 percent of the calculated current derived from both: the Real Power output of 100 percent of the maximum gross MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 150 percent of the MW value, derived from the generator nameplate MVA rating at rated power factor. For Option 2c, the overcurrent element isshall be set greater than the calculated current derived from 115 percent of both: the Real Power output of 100 percent of the maximum gross MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 100 percent of the maximum gross Mvar output during field‐forcing as determined by simulation. Synchronous Generators Phase Time Overcurrent Relay – Voltage Controlled (e.g., 51V-C) (Option 3) Table 1, Option 3, is provided for assessing loadability for synchronous generators applying phase time overcurrent relays which are enabled as a function of voltage (“voltage‐controlled”). These margins are based on guidance found in section 3.10Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Option 3 calculates the generator bus voltage corresponding to 1.0 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying athe 1.0 per unit nominal voltage, at the high‐side terminals of the GSU transformer times, by the GSU transformer turns ratio (excluding the impedance). This is a simple calculation that approximates the stressed system conditions. For Option 3, the voltage control setting isshall be set less than 75 percent of the calculated generator bus voltage. The voltage setting must be set such that the function (e.g., 51V‐C) will not trip under extreme emergency conditions as the time overcurrent function will be set less than generator full load current. Relays enabled as a function of voltage are indifferent as to the current setting, and this option simply requires that the relays not respond for the depressed voltage.


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Asynchronous Generators Phase Distance Relay – Directional Toward Transmission System (e.g., 21) (Option 4) Table 1, Option 4 is provided for assessing loadability for asynchronous generators applying phase distance relays that are directional toward the Transmission system. These margins are based on guidance found in section 3.1Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Option 4 calculates the generator bus voltage corresponding to 1.0 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying athe 1.0 per unit nominal voltage, at the high‐side terminals of the GSU transformer times, by the GSU transformer turns ratio (excluding the impedance). This is a simple calculation that approximates the stressed system conditions. Since the relay voltage is supplied from the generator bus, it is necessary to assess loadability using the generator‐side voltage. Asynchronous generators do not produce as much Reactive Power as synchronous generators; the voltage drop due to Reactive Power flow through the GSU transformer is not as significant. Therefore, the generator bus voltage can be conservatively estimated by reflecting the high‐side nominal voltage to the generator‐side based on the GSU transformer’s turns ratio. Since the relay voltage is supplied from the generator bus, it is necessary to assess loadability using the generator-side voltage. Asynchronous generators do not produce as much Reactive Power as synchronous generators; the voltage drop due to Reactive Power flow through the GSU transformer is not as significant. Therefore, the generator bus voltage can be conservatively estimated by reflecting the high‐side nominal voltage to the generator‐side based on the GSU transformer’s turns ratio. For Option 4, the impedance element isshall be set less than the calculated impedance derived from 130 percent of the maximum aggregate nameplate MVA output at rated power factor including the Mvar output of any static or dynamic Reactive Power devices. This is determined by summing the total MW and Mvar capability of the generation equipment behind the relay and any static or dynamic Reactive Power devices that contribute to the power flow through the relay. Asynchronous Generators Phase Time Overcurrent Relay – (e.g., 50, 51, or 51V-R – Voltage- Restrained (51V-R) (Option 5) (Options 5a and 5b) Table 1, Option 55a is provided for assessing loadability for asynchronous generators applying phase time overcurrent relays (e.g., 50 or 51) or voltage‐restrained (e.g., 51V‐R) which change theirchanges its sensitivity as a function of voltage (“voltage‐restrained”). These margins are based on guidance found in section 3.10Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Option 55a calculates the generator bus voltage corresponding to 1.0 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying athe 1.0 per unit nominal voltage, at the high‐side terminals of the GSU transformer


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times, by the GSU transformer turns ratio (excluding the impedance). This is a simple calculation that approximates the stressed system conditions. Since the relay voltage is supplied from the generator bus, it is necessary to assess loadability using the generator‐side voltage. Asynchronous generators do not produce as much Reactive Power as synchronous generators; the voltage drop due to Reactive Power flow through the GSU transformer is not as significant. Therefore, the generator bus voltage can be conservatively estimated by reflecting the high‐side nominal voltage to the generator‐side based on the GSU transformer’s turns ratio. Since the relay voltage is supplied from the generator bus, it is necessary to assess loadability using the generator‐side voltage. Asynchronous generators do not produce as much Reactive Power as synchronous generators; the voltage drop due to Reactive Power flow through the GSU transformer is not as significant. Therefore, the generator bus voltage can be conservatively estimated by reflecting the high‐side nominal voltage to the generator‐side based on the GSU transformer’s turns ratio. For Option 55a, the overcurrent element isshall be set greater than 130 percent of the calculated current derived from the maximum aggregate nameplate MVA output at rated power factor including the Mvar output of any static or dynamic Reactive Power devices. This is determined by summing the total MW and Mvar capability of the generation equipment behind the relay and any static or dynamic Reactive Power devices that contribute to the power flow through the relay. For Option 5b, the overcurrent element shall be set to exceed the maximum capability of the asynchronous resource and applicable equipment (e.g., windings, power electronics, cables, or bus). This is determined by summing the total current capability of the generation equipment behind the overcurrent element and any static or dynamic Reactive Power devices that contribute to the power flow through the overcurrent element. The overcurrent element shall be set to not infringe upon the resource capability with worst case documented tolerances applied to the setting. Figure A illustrates that the overcurrent element does not infringe upon the asynchronous resource capability. The upper hashed area of Figure A represents Exclusion 7. Asynchronous Generator Phase Time Overcurrent Relays – Voltage Controlled (e.g., 51V-C) (Option 6) Table 1, Option 6, is provided for assessing loadability for asynchronous generators applying phase time overcurrent relays which are enabled as a function of voltage (“voltage‐controlled”). These margins are based on guidance found in section 3.10Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Option 6 calculates the generator bus voltage corresponding to 1.0 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying athe 1.0 per unit nominal voltage, at the high‐side terminals of the GSU transformer times, by the GSU transformer turns ratio (excluding the impedance). This is a simple calculation that approximates the stressed system conditions.


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For Option 6, the voltage control setting isshall be set less than 75 percent of the calculated generator bus voltage. The voltage setting must be set such that the function (e.g., 51V‐C) will not trip under extreme emergency conditions as the time overcurrent function will be set less than generator full load current. Relays enabled as a function of voltage are indifferent as to the current setting, and this option simply requires that the relays not respond for the depressed voltage. Generator Step-up Transformer (Synchronous Generators) Phase Distance Relays – Directional Toward Transmission System (e.g., 21) (Options 7a, 7b, and 7c) The Federal Energy Regulatory Commission, in FERC Order No. 733, paragraph 104, directs that NERC address relay loadability for protective relays applied on GSU transformers. These margins are based on guidance found in section 3.1Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Table 1, Options 7a, 7b, and 7c, are provided for assessing loadability for GSU transformers applyingof phase distance relays that are directional toward the Transmission system on synchronous generators that areand connected to the generator‐side of the GSU transformer of a synchronous generator. WhereFor applications where the relay is connected on the high‐side of the GSU transformer, use Option 14. Option 7a calculates a generator bus voltage corresponding to 0.95 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying athe 0.95 per unit nominal voltage, at the high‐side terminals of the GSU transformer times, by the GSU transformer turns ratio (excluding the impedance). This is the simplest calculation that approximatesis a straightforward way to approximate the stressed system conditions. Option 7b calculates the generator bus voltage corresponding to 0.85 per unit nominal voltage on the high‐side terminals of the GSU transformer. The voltage drop across the GSU transformer is calculated based on athe 0.85 per unit nominal voltage, at the high‐side terminals of the GSU transformer and accounts for, as well as the turns ratio and impedance. The actual generator bus voltage may be higher depending on the GSU transformer impedance and the actual Reactive Power achieved. This calculation is a more involved, morein‐depth and precise method for setting of the impedance element than Option 7a. Option 7c simulates the generator bus voltage coincident with the highest Reactive Power output achieved during field‐forcing. This output is in response to a 0.85 per unit nominal voltage on the high‐side terminals of the GSU transformer prior to field‐forcing. Using simulation is a more involved, morein‐depth and precise method for setting of the overcurrentimpedance element overallthan Options 7a or 7b. For Options 7a and 7b, the impedance element isshall be set less than the calculated impedance derived from 115 percent of both: the Real Power output of 100 percent of the aggregate


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generation MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 150 percent of the aggregate generation MW value, (derived from the generator nameplate MVA rating at rated power factor.). For Option 7c, the impedance element isshall be set less than the calculated impedance derived from 115 percent of both: the Real Power output of 100 percent of the aggregate generation MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 100 percent of the maximum gross Mvar output during field‐forcing as determined by simulation. Generator Step-up Transformer (Synchronous Generators) Phase Time Overcurrent Relay (e.g., 50 or 51) (Options 8a, 8b and 8c) The Federal Energy Regulatory Commission, in FERC Order No. 733, paragraph 104, directs that NERC address relay loadability for protective relays applied on GSU transformers. Note that the setting criteria established within the Table 1 options differs from Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Rather than establishing a uniform loadability threshold of 200 percent of the generator nameplate MVA rating at rated power factor for all applications, the setting criteria are based on the maximum expected generator output. Table 1, Options 8a, 8b, and 8c, are provided for assessing loadability of phase overcurrent relays that are connected to the generator‐side of the GSU transformer of a synchronous generator. For applications where the relay is connected on the high‐side of the GSU transformer, use Option 15. Option 8a calculates a generator bus voltage corresponding to 0.95 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying the 0.95 per unit nominal voltage, at the high‐side terminals of the GSU transformer, by the GSU transformer turns ratio (excluding the impedance). This calculation is a straightforward way to approximate the stressed system conditions. Option 8b calculates the generator bus voltage corresponding to 0.85 per unit nominal voltage on the high‐side terminals of the GSU transformer. The voltage drop across the GSU transformer is calculated based on the 0.85 per unit nominal voltage, at the high‐side terminals of the GSU transformer, as well as the turns ratio and impedance. The actual generator bus voltage may be higher depending on the GSU transformer impedance and the actual Reactive Power achieved. This calculation is a more in‐depth and precise method for setting the overcurrent element than Option 8a. Option 8c simulates the generator bus voltage coincident with the highest Reactive Power output achieved during field‐forcing. This output is in response to a 0.85 per unit nominal voltage on the high‐side terminals of the GSU transformer prior to field‐forcing. Using simulation is a more in‐depth and precise method for setting the overcurrent element than Options 8a or 8b.


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For Options 8a and 8b, the overcurrent element shall be set greater than 115 percent of the calculated current derived from both: the Real Power output of 100 percent of the aggregate generation MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 150 percent of the aggregate generation MW value (derived from the generator nameplate MVA rating at rated power factor). For Option 8c, the overcurrent element shall be set greater than 115 percent of the calculated current derived from both: the Real Power output of 100 percent of the aggregate generation MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 100 percent of the maximum gross Mvar output during field‐forcing as determined by simulation. Generator Step-up Transformer (Synchronous Generators) Phase Directional Overcurrent Relay – Directional Toward Transmission System (e.g., 67) (Options 9a, 9b and 9c) The Federal Energy Regulatory Commission, in FERC Order No. 733, paragraph 104, directs that NERC address relay loadability for protective relays applied on GSU transformers. Note that the setting criteria established within thesethe Table 1 options differdiffers from section 3.9.Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Rather than establishing a uniform setting threshold of 200 percent of the generator nameplate MVA rating at rated power factor for all applications, the setting criteria are based on the maximum expected generator output. Table 1, Options 8a, 8b, and 8c, are provided for assessing loadability for GSU transformers applying phase time overcurrent relays on synchronous generators that are connected to the generator-side of the GSU transformer of a synchronous generator. Where the relay is connected on the high-side of the GSU transformer, use Option 15. Option 8a calculates a generator bus voltage corresponding to 0.95 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying a 0.95 per unit nominal voltage at the high-side terminals of the GSU transformer times the GSU transformer turns ratio (excluding the impedance). This is the simplest calculation that approximates the stressed system conditions.

Option 8b calculates the generator bus voltage corresponding to 0.85 per unit nominal voltage on the high‐side terminals of the GSU transformer. The voltage drop across the GSU transformer is calculated based on a 0.85 per unit nominal voltage at the high-side terminals of the GSU transformer and accounts for the turns ratio and impedance. The actual generator bus voltage may be higher depending on the GSU transformer impedance and the actual Reactive Power achieved. This calculation is a more involved, more precise setting of the impedance element than Option 8a.

Option 8c simulates the generator bus voltage coincident with the highest Reactive Power output achieved during field-forcing in response to a 0.85 per unit nominal voltage on the high-side terminals of the GSU transformer prior to field-forcing. Using simulation is a more involved, more precise setting of the overcurrent element overall.

For Options 8a and 8b, the overcurrent element is set greater than 115 percent of the calculated current derived from: the Real Power output of 100 percent of the aggregate generation MW


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capability reported to the Transmission Planner, and Reactive Power output that equates to 150 percent of the aggregate generation MW value, derived from the generator nameplate MVA rating at rated power factor.

For Option 8c, the overcurrent element is set greater than 115 percent of the calculated current derived from: the Real Power output of 100 percent of the aggregate generation MW capability reported to the Transmission Planner, and Reactive Power output that equates to 100 percent of the maximum gross Mvar output during field-forcing as determined by simulation.

Generator Step-up Transformer (Synchronous Generators) Phase Directional Time Overcurrent Relay – Directional Toward Transmission System (67) (Options 9a, 9b and 9c) The Federal Energy Regulatory Commission, in FERC Order No. 733, paragraph 104, directs that NERC address relay loadability for protective relays applied on GSU transformers. Note that the setting criteria established within these options differ from section 3.9.2 of the Power Plant and Transmission System Protection Coordination technical reference document. Rather than establishing a uniform settingloadability threshold of 200 percent of the generator nameplate MVA rating at rated power factor for all applications, the setting criteria are based on the maximum expected generator output. Table 1, Options 9a, 9b, and 9c, are provided for assessing loadability for GSU transformers applyingof phase directional time overcurrent relays directional toward the Transmission System that are connected to the generator‐side of the GSU transformer of a synchronous generator. WhereFor applications where the relay is connected on the high‐side of the GSU transformer, use Option 16. Option 9a calculates a generator bus voltage corresponding to 0.95 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying athe 0.95 per unit nominal voltage, at the high‐side terminals of the GSU transformer times, by the GSU transformer turns ratio (excluding the impedance). This is the simplest calculation that approximatesis a straightforward way to approximate the stressed system conditions. Option 9b calculates the generator bus voltage corresponding to 0.85 per unit nominal voltage on the high‐side terminals of the GSU transformer. The voltage drop across the GSU transformer is calculated based on athe 0.85 per unit nominal voltage, at the high‐side terminals of the GSU transformer and accounts for, as well as the turns ratio and impedance. The actual generator bus voltage may be higher depending on the GSU transformer impedance and the actual Reactive Power achieved. This calculation is a more involved, morein‐depth and precise method for setting of the impedanceovercurrent element than Option 9a. Option 9c simulates the generator bus voltage coincident with the highest Reactive Power output achieved during field‐forcing. This output is in response to a 0.85 per unit nominal voltage on the high‐side terminals of the GSU transformer prior to field‐forcing. Using simulation is a more


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involved, morein‐depth and precise method for setting of the overcurrent element overallthan Options 9a or 9b. For Options 9a and 9b, the overcurrent element isshall be set greater than 115 percent of the calculated current derived from both: the Real Power output of 100 percent of the aggregate generation MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 150 percent of the aggregate generation MW value, (derived from the generator nameplate MVA rating at rated power factor.). For Option 9c, the overcurrent element isshall be set greater than 115 percent of the calculated current derived from both: the Real Power output of 100 percent of the aggregate generation MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 100 percent of the maximum gross Mvar output during field‐forcing as determined by simulation. Generator Step-up Transformer (Asynchronous Generators) Phase Distance Relay – Directional Toward Transmission System (e.g., 21) (Option 10) The Federal Energy Regulatory Commission, in FERC Order No. 733, paragraph 104, directs that NERC address relay loadability for protective relays applied on GSU transformers. Table 1, Option 10 is provided for assessing loadability for GSU transformers applying phase distance relays that are directional toward the Transmission System that are connected to the generator‐side of the GSU transformer of an asynchronous generator. These margins are based on guidance found in section 3.1Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. WhereFor applications where the relay is connected on the high‐side of the GSU transformer, use Option 17. Option 10 calculates the generator bus voltage corresponding to 1.0 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying athe 1.0 per unit nominal voltage, at the high‐side terminals of the GSU transformer times, by the GSU transformer turns ratio (excluding the impedance). This is a simple calculation that approximatesis a straightforward way to approximate the stressed system conditions. Since the relay voltage is supplied from the generator bus, it is necessary to assess loadability using the generator‐side voltage. Asynchronous generators do not produce as much Reactive Power as synchronous generators; the voltage drop due to Reactive Power flow through the GSU transformer is not as significant. Therefore, the generator bus voltage can be conservatively estimated by reflecting the high‐side nominal voltage to the generator‐side based on the GSU transformer’s turns ratio. Since the relay voltage is supplied from the generator bus, it is necessary to assess loadability using the generator‐side voltage. Asynchronous generators do not produce as much Reactive Power as synchronous generators; hence the voltage drop due to Reactive Power flow through the GSU transformer is not as significant. Therefore, the generator bus voltage can be conservatively estimated by reflecting the high‐side nominal voltage to the generator‐side based on the GSU transformer’s turns ratio.


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For Option 10, the impedance element isshall be set less than the calculated impedance, derived from 130 percent of the maximum aggregate nameplate MVA output at rated power factor, including the Mvar output of any static or dynamic Reactive Power devices. This is determined by summing the total MW and Mvar capability of the generation equipment behind the relay and any static or dynamic Reactive Power devices that contribute to the power flow through the relay. Generator Step-up Transformer (Asynchronous Generators) Phase Time Overcurrent Relay (e.g., 50 or 51) (Option 11) The Federal Energy Regulatory Commission, in FERC Order No. 733, paragraph 104, directs that NERC address relay loadability for protective relays applied on GSU transformers. The Federal Energy Regulatory Commission, in FERC Order No. 733, paragraph 104, directs that NERC address relay loadability for protective relays applied on GSU transformers. Note that the setting criteria established within thesethe Table 1 options differdiffers from section 3.9.Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Rather than establishing a uniform settingloadability threshold of 200 percent of the generator nameplate MVA rating at rated power factor for all applications, the setting criteria are based on the maximum expected generator output. Table 1, Option 11 is provided for assessing loadability for GSU transformers applyingof phase time overcurrent relays on asynchronous generators that are connected to the generator‐side of the GSU transformer. Where of an asynchronous generator. For applications where the relay is connected on the high‐side of the GSU transformer, use Option 18. Option 11 calculates the generator bus voltage corresponding to 1.0 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying athe 1.0 per unit nominal voltage, at the high‐side terminals of the GSU transformer times, by the GSU transformer turns ratio (excluding the impedance). This is a simple calculation that approximatesis a straightforward way to approximate the stressed system conditions. Since the relay current is supplied from the generator bus, it is necessary to assess loadability using the generator‐side voltage. Asynchronous generators do not produce as much Reactive Power as synchronous generators; hence the voltage drop due to Reactive Power flow through the GSU transformer is not as significant. Therefore, the generator bus voltage can be conservatively estimated by reflecting the high‐side nominal voltage to the generator‐side based on the GSU transformer’s turns ratio. the voltage drop due to Reactive Power flow through the GSU transformer is not as significant.

Therefore, the generator bus voltage can be conservatively estimated by reflecting the high‐side nominal voltage to the generator‐side based on the GSU transformer’s turns ratio.

For Option 11, the overcurrent element isshall be set greater than 130 percent of the calculated current derived from the maximum aggregate nameplate MVA output at rated power factor, including the Mvar output of any static or dynamic Reactive Power devices. This is determined


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by summing the total MW and Mvar capability of the generation equipment behind the relay and any static or dynamic Reactive Power devices that contribute to the power flow through the relay. Generator Step-up Transformer (Asynchronous Generators) Phase Directional Overcurrent Relay – Directional Toward Transmission System (e.g., 67) (Option 12) The Federal Energy Regulatory Commission, in FERC Order No. 733, paragraph 104, directs that NERC address relay loadability for protective relays applied on GSU transformers. Note that the setting criteria established within the Table 1 options differs from Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Rather than establishing a uniform loadability threshold of 200 percent of the generator nameplate MVA rating at rated power factor for all applications, the setting criteria are based on the maximum expected generator output. Table 1, Option 12 is provided for assessing loadability of phase directional overcurrent relays directional toward the Transmission System that are connected to the generator‐side of the GSU transformer of an asynchronous generator. For applications where the relay is connected on the high‐side of the GSU transformer, use Option 19. Option 12 calculates the generator bus voltage corresponding to 1.0 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying the 1.0 per unit nominal voltage, at the high‐side terminals of the GSU transformer, by the GSU transformer turns ratio (excluding the impedance). This calculation is a straightforward way to approximate the stressed system conditions. Since the relay current is supplied from the generator bus, it is necessary to assess loadability using the generator‐side voltage. Asynchronous generators do not produce as much Reactive Power as synchronous generators; hence the voltage drop due to Reactive Power flow through the GSU transformer is not as significant. Therefore, the generator bus voltage can be conservatively estimated by reflecting the high‐side nominal voltage to the generator‐side based on the GSU transformer’s turns ratio. For Option 12, the overcurrent element shall be set greater than 130 percent of the calculated current derived from the maximum aggregate nameplate MVA output at rated power factor, including the Mvar output of any static or dynamic Reactive Power devices. This is determined by summing the total MW and Mvar capability of the generation equipment behind the relay and any static or dynamic Reactive Power devices that contribute to the power flow through the relay.


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Generator Step-up Transformer (Asynchronous Generators) Phase Directional Time Overcurrent Relay – Directional Toward Transmission System (67) (Option 12) The Federal Energy Regulatory Commission, in FERC Order No. 733, paragraph 104, directs that NERC address relay loadability for protective relays applied on GSU transformers. Note that the setting criteria established within these options differ from section 3.9.2 of the Power Plant and Transmission System Protection Coordination technical reference document. Rather than establishing a uniform setting threshold of 200 percent of the generator nameplate MVA rating at rated power factor for all applications, the setting criteria are based on the maximum expected generator output.

Table 1, Option 12 is provided for assessing loadability for GSU transformers applying phase directional time overcurrent relays directional toward the Transmission System on asynchronous generators that are connected to the generator-side of the GSU transformer of an asynchronous generator. Where the relay is connected on the high-side of the GSU transformer, use Option 19. Option 12 calculates the generator bus voltage corresponding to 1.0 per unit nominal voltage on the high‐side terminals of the GSU transformer. The generator bus voltage is calculated by multiplying a 1.0 per unit nominal voltage at the high-side terminals of the GSU transformer times the GSU transformer turns ratio (excluding the impedance). This is a simple calculation that approximates the stressed system conditions. Since the relay current is supplied from the generator bus, it is necessary to assess loadability using the generator‐side voltage. Asynchronous generators do not produce as much Reactive Power as synchronous generators; the voltage drop due to Reactive Power flow through the GSU transformer is not as significant. Therefore, the generator bus voltage can be conservatively estimated by reflecting the high‐side nominal voltage to the generator‐side based on the GSU transformer’s turns ratio. For Option 12, the overcurrent element is set greater than 130 percent of the calculated current derived from the maximum aggregate nameplate MVA output at rated power factor including the Mvar output of any static or dynamic Reactive Power devices. This is determined by summing the total MW and Mvar capability of the generation equipment behind the relay and any static or dynamic Reactive Power devices that contribute to the power flow through the relay. Unit Auxiliary Transformers Phase Time Overcurrent Relay (e.g., 50 or 51) (Options 13a and 13b) In FERC Order No. 733, paragraph 104, directs NERC to include in this standard a loadability requirement for relays used for overload protection of the UAT that supply normal station service for a generating unit. For the purposes of this standard, UATs provide the overall station power to support the unit at its maximum gross operation. Table 1, Options 13a and 13b provide two options for addressing phase time overcurrent relaying applied at the high‐side of UATs. The transformer high‐side winding may be directly connected to the transmission grid or at the generator isolated phase bus (IPB) or iso‐phase bus. Phase time overcurrent relays applied at the high‐side of the UAT that remove the transformer from service resulting in an immediate (e.g., via lockout or auxiliary tripping relay operation) or consequential trip of the associated generator are to be compliant with the relay setting criteria in this standard.


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Due to the complexity of the application of low‐side overload relays for single or multi‐winding transformers, phase time overcurrent relaying applied toat the low‐side of the UAT are not addressed in this standard. These relays include, but are not limited to, a relay used for arc flash protection, feeder protection relays, breaker failure, and relays whose operation may result in a generator runback. Although the UAT is not directly in the output path from the generator to the Transmission system, it is an essential component for operation of the generating unit or plant.

Refer to the Figures 6 and 7 below for example configurations:

Unit AuxiliaryTransformers

System

System

Station Loads

Transfer Switch

GSU

G

TransformersCovered by this

standard

Figure‐6 – Auxiliary Power System (independent from generator).


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Figure‐7 – Typical auxiliary power system for generation units or plants.

The UATs supplying power to the unit or plant electrical auxiliaries are sized to accommodate the maximum expected overall UAT load demand at the highest generator output. Although the transformer nameplate MVA size normally includes capacity for future loads as well as capacity for starting of large induction motors on the original unit or plant design, the nameplate MVA capacity of the transformer may be near full load. Because of the various design and loading characteristics of UATs, two options (i.e., 13a and 13b) are provided to accommodate an entity’s protection philosophy while preventing the UAT transformer phase time overcurrent relays from operating during the dynamic conditions anticipated by this standard. Options 13a and 13b are based on the transformer bus voltage corresponding to 1.0 per unit nominal voltage on the high‐side winding of the UAT. For Option 13a, the overcurrent element shall be set greater than 150 percent of the calculated current derived from the UAT maximum nameplate MVA rating. This is a simple calculation that approximates the stressed system conditions. For Option 13b, the overcurrent element shall be set greater than 150 percent of the UAT measured current at the generator maximum gross MW capability reported to the Transmission Planner. This allows for a reduced setting pickup compared to Option 13a and the entity’s relay setting philosophy. This is a more involved calculation that approximates the stressed system conditions by allowing the entity to consider the actual load placed on the UAT based on the generator’s maximum gross MW capability reported to the Transmission Planner. The performance of the UAT loads during stressed system conditions (i.e., depressed voltages) is very difficult to determine. Rather than requiring responsible entities to determine the response


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of UAT loads to depressed voltage, the technical experts writing the standard elected to increase the margin to 150 percent from that used elsewhere in this standard (e.g., 115 percent) and use a generator bus voltage of 1.0 per unit. A minimum pickupsetting current based on 150 percent of maximum transformer nameplate MVA rating at 1.0 per unit generator bus voltage will provide adequate transformer protection based on IEEE C37.91 at full load conditions while providing sufficient relay loadability to prevent a trip of the UAT, and subsequent unit trip, due to increased UAT load current during stressed system voltage conditions. Even if the UAT is equipped with an automatic tap changer, the tap changer may not respond quickly enough for the conditions anticipated within this standard, and thus shall not be used to reduce this margin. Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant (Synchronous Generators) Phase Distance Relays – Directional Toward Transmission System (e.g., 21) (Options 14a and 14b) Relays applied on Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant are challenged by loading conditions similar to relays applied on generators and GSU transformers. Relays applied on Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant are challenged by loading conditions similar to relays applied on generators and GSU transformers. These margins are based on guidance found in section 3.1Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Relays applied on the high‐side of the GSU transformer respond to the same quantities as the relays connected on the Elements that connect a GSU transformer to the Transmission system (e.g., at the remote end of the line) that are used exclusively to export energy directly from a BES generating unit or generating plant, thus Option 14 is used for these relays as well. Table 1, Options 14a and 14b, establish criteria for phase distance relays directional toward the Transmission system to prevent Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant from operatingtripping during the dynamic conditions anticipated by this standard. The stressed system conditions, anticipated by Option 14a reflects a 0.85 per unit Transmission systemof the line nominal voltage; therefore, establishing that the impedance value used for applying the Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant phase distance relays that are directional toward the Transmission system be calculated from the apparent power addressed within the criteria, with application of a 0.85 per unit Transmission systemof the line nominal voltage at the relay location. Consideration of the voltage drop across the GSU transformer is not necessary. Option 14b simulates the line voltage coincident with the highest Reactive Power output achieved during field‐forcing in response to a 0.85 per unit nominal voltage on the high-side terminals of the GSU transformer prior to field-forcing.line nominal voltage at the remote end of the line prior to field‐forcing. Using a 0.85 per unit line nominal voltage at the remote end of the line is representative of the lowest voltage expected during a depressed voltage condition on Elements that are used exclusively to export energy


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directly from a BES generating unit or generating plant to the Transmission system. Using simulation is a more involved, more precise setting of the overcurrent element overall. For Option 14a, the impedance element isshall be set less than the calculated impedance derived from 115 percent of both: the Real Power output of 100 percent of the aggregate generation MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 120 percent of the aggregate generation MW value, derived from the generator nameplate MVA rating at rated power factor. This Reactive Power value differs from the 150 percent multiplier used in other applicationapplications to account for the Reactive Power losses in the GSU transformer. This is a simple calculation that approximates the stressed system conditions. For Option 14b, the impedance element isshall be set less than the calculated impedance derived from 115 percent of both: the Real Power output of 100 percent of the aggregate generation MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 100 percent of the maximum gross Mvar output during field‐forcing as determined by simulation. Using simulation is a more involved, more precise setting of the impedance element overall. Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant (Synchronous Generators) Phase Time Overcurrent Relay (e.g., 50 or 51) (Options 15a and 15b) Relays applied on Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant are challenged by loading conditions similar to relays applied on generators and GSU transformers. Note that the setting criteria established within thesethe Table 1 options differdiffers from section 3.9.Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Rather than establishing a uniform setting threshold of 200 percent of the generator nameplate MVA rating at rated power factor for all applications, the setting criteria are based on the maximum expected generator output. Relays applied on the high‐side of the GSU transformer respond to the same quantities as the relays connected on the Elements that connect a GSU transformer to the Transmission system (e.g., at the remote end of the line) that are used exclusively to export energy directly from a BES generating unit or generating plant, thus Option 15 is used for these relays as well. Table 1, Options 15a and 15b, establish criteria for phase instantaneous and/or time overcurrent relays to prevent Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant from operatingtripping during the dynamic conditions anticipated by this standard. The stressed system conditions, anticipated by Option 15a reflects a 0.85 per unit Transmission systemof the line nominal voltage at the relay location; therefore, establishing that the current value used for applying the Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant phase


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instantaneous and/or time overcurrent relays be calculated from the apparent power addressed within the criteria, with application of a 0.85 per unit Transmission systemof the line nominal voltage at the relay location. Consideration of the voltage drop across the GSU transformer is not necessary. Option 15b simulates the line voltage coincident with the highest Reactive Power output achieved during field‐forcing in response to a 0.85 per unit nominal voltage on the high-side terminals of the GSU transformer prior to field-forcing.line nominal voltage at the remote end of the line prior to field‐forcing. Using a 0.85 per unit line nominal voltage at the remote end of the line is representative of the lowest voltage expected during a depressed voltage condition on Elements that are used exclusively to export energy directly from a BES generating unit or generating plant to the Transmission system. Using simulation is a more involved, more precise setting of the overcurrent element overall. For Option 15a, the overcurrent element isshall be set greater than 115 percent of the calculated current derived from both: the Real Power output of 100 percent of the aggregate generation MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 120 percent of the aggregate generation MW value, derived from the generator nameplate MVA rating at rated power factor. This Reactive Power value differs from the 150 percent multiplier used in other applicationapplications to account for the Reactive Power losses in the GSU transformer. This is a simple calculation that approximates the stressed system conditions. For Option 15b, the overcurrent element isshall be set greater than 115 percent of the calculated current derived from both: the Real Power output of 100 percent of the aggregate generation MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 100 percent of the maximum gross Mvar output during field‐forcing as determined by simulation. Using simulation is a more involved, more precise setting of the overcurrent element overall. Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant (Synchronous Generators) Phase Directional Time Overcurrent Relay – Directional Toward Transmission System (e.g., 67) (Options 16a and 16b) Relays applied on Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant are challenged by loading conditions similar to relays applied on generators and GSU transformers. Relays applied on Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant are challenged by loading conditions similar to relays applied on generators and GSU transformers. Note that the setting criteria established within thesethe Table 1 options differdiffers from section 3.9.Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Rather than establishing a uniform setting threshold of 200 percent of the generator nameplate MVA rating at rated power factor for all applications, the setting criteria are based on the maximum expected generator output. Relays applied on the high‐side of the GSU transformer respond to the same quantities as the relays connected on the


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Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant, thus Option 16 is used for these relays as well. Table 1, Options 16a and 16b, establish criteria for phase directional time overcurrent relays that are directional toward the Transmission system to prevent Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant from operatingtripping during the dynamic conditions anticipated by this standard. The stressed system conditions, anticipated by Option 16a reflects a 0.85 per unit Transmission systemof the line nominal voltage at the relay location; therefore, establishing that the current value used for applying the interconnection Facilities phase directional time overcurrent relays be calculated from the apparent power addressed within the criteria, with application of a 0.85 per unit Transmission systemof the line nominal voltage at the relay location. Consideration of the voltage drop across the GSU transformer is not necessary. Option 16b simulates the line voltage coincident with the highest Reactive Power output achieved during field‐forcing in response to a 0.85 per unit nominal voltage on the high-side terminals of the GSU transformer prior to field-forcing.line nominal voltage at the remote end of the line prior to field‐forcing. Using a 0.85 per unit line nominal voltage at the remote end of the line is representative of the lowest voltage expected during a depressed voltage condition on Elements that are used exclusively to export energy directly from a BES generating unit or generating plant to the Transmission system. Using simulation is a more involved, more precise setting of the overcurrent element overall. For Option 16a, the overcurrent element isshall be set greater than 115 percent of the calculated current derived from both: the Real Power output of 100 percent of the aggregate generation MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 120 percent of the aggregate generation MW value, derived from the generator nameplate MVA rating at rated power factor. This Reactive Power value differs from the 150 percent multiplier used in other applicationapplications to account for the Reactive Power losses in the GSU transformer. This is a simple calculation that approximates the stressed system conditions. For Option 16b, the overcurrent element isshall be set greater than 115 percent of the calculated current derived from both: the Real Power output of 100 percent of the aggregate generation MW capability reported to the Transmission Planner, and the Reactive Power output that equates to 100 percent of the maximum gross Mvar output during field‐forcing as determined by simulation. Using simulation is a more involved, more precise setting of the overcurrent element overall.


67 of 129

Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant (Asynchronous Generators) Phase Distance Relay – Directional Toward Transmission System (e.g., 21) (Option 17) Relays applied on Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant are challenged by loading conditions similar to relays applied on generators and GSU transformers. Relays applied on Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant are challenged by loading conditions similar to relays applied on generators and GSU transformers. These margins are based on guidance found in section 3.1Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Table 1, Option 17 establishes criteria for phase distance relays that are directional toward the Transmission system to prevent Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant from operatingtripping during the dynamic conditions anticipated by this standard. Option 17 applies a 1.0 per unit line nominal voltage onat the high-side terminals of the GSU transformerrelay location to calculate the impedance from the maximum aggregate nameplate MVA. Asynchronous generators do not produce as much Reactive Power as synchronous generators; the voltage drop due to Reactive Power flow through the GSU transformer is not as significant. For Option 17, the impedance element isshall be set less than the calculated impedance derived from 130 percent of the maximum aggregate nameplate MVA output at rated power factor including the Mvar output of any static or dynamic Reactive Power devices. This is determined by summing the total MW and Mvar capability of the generation equipment behind the relay and any static or dynamic Reactive Power devices that contribute to the power flow through the relay. This is a simple calculation that approximates the stressed system conditions. Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant (Asynchronous Generators) Phase Time Overcurrent Relay (e.g., 50 and 51) (Option 18) Relays applied on Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant are challenged by loading conditions similar to relays applied on generators and GSU transformers. Relays applied on Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant are challenged by loading conditions similar to relays applied on generators and GSU transformers. Note that the setting criteria established within thesethe Table 1 options differdiffers from section 3.9.Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Rather than establishing a uniform setting threshold of 200 percent of the generator nameplate MVA rating at rated power factor for all applications, the setting criteria are based on the maximum expected generator output.


68 of 129

Table 1, Option 18 establishes criteria for phase time overcurrent relays to prevent Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant from operatingtripping during the dynamic conditions anticipated by this standard. Option 18 applies a 1.0 per unit line nominal voltage onat the high-side terminalslocation of the GSU transformerrelay to calculate the current from the maximum aggregate nameplate MVA. Asynchronous generators do not produce as much Reactive Power as synchronous generators; the voltage drop due to Reactive Power flow through the GSU transformer is not as significant. For Option 18, the overcurrent element isshall be set greater than 130 percent of the calculated current derived from the maximum aggregate nameplate MVA output at rated power factor including the Mvar output of any static or dynamic Reactive Power devices. This is determined by summing the total MW and Mvar capability of the generation equipment behind the relay and any static or dynamic Reactive Power devices that contribute to the power flow through the relay. This is a simple calculation that approximates the stressed system conditions. Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant (Asynchronous Generators) Phase Directional Time Overcurrent Relay – Directional Toward Transmission System (e.g., 67) (Option 19) Relays applied on Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant are challenged by loading conditions similar to relays applied on generators and GSU transformers. Relays applied on Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant are challenged by loading conditions similar to relays applied on generators and GSU transformers. Note that the setting criteria established within thesethe Table 1 options differdiffers from section 3.9.Chapter 2 of the Considerations for Power Plant and Transmission System Protection Coordination technical reference document. Rather than establishing a uniform setting threshold of 200 percent of the generator nameplate MVA rating at rated power factor for all applications, the setting criteria are based on the maximum expected generator output. Table 1, Option 19 establishes criteria for phase directional time overcurrent relays that are directional toward the Transmission system to prevent Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant from operatingtripping during the dynamic conditions anticipated by this standard. Option 19 applies a 1.0 per unit line nominal voltage onat the high-side terminals of the GSU transformerrelay location to calculate the current from the maximum aggregate nameplate MVA. Asynchronous generators do not produce as much Reactive Power as synchronous generators; the voltage drop due to Reactive Power flow through the GSU transformer is not as significant.


69 of 129

For Option 19, the overcurrent element isshall be set greater than 130 percent of the calculated current derived from the maximum aggregate nameplate MVA output at rated power factor including the Mvar output of any static or dynamic Reactive Power devices. This is determined by summing the total MW and Mvar capability of the generation equipment behind the relay and any static or dynamic Reactive Power devices that contribute to the power flow through the relay. This is a simple calculation that approximates the stressed system conditions.


70 of 129

Example Calculations Introduction


Input Descriptions Input Values

Synchronous Generator nameplate (MVA @ rated pf): _ 903

0.85

Generator rated voltage (Line‐to‐Line): _ 22

Real Power output in MW as reported to the TP: _ 700.0

Generator step‐up (GSU) transformer rating: 903

GSU transformer reactance (903 MVA base): 12.14%

GSU transformer MVA base: 767.6

GSU transformer turns ratio: 22346.5

High‐side nominal system voltage (Line‐to‐Line): 345

Current transformer (CT) ratio: 250005

Potential transformer (PT) ratio low‐side: 2001

PT ratio high‐side: _20001

Unit auxiliary transformer (UAT) nameplate: 60

UAT low‐side voltage: 13.8

UAT CT ratio: 50005

CT high voltage ratio: _20005


71 of 129


Reactive Power output of static reactive device: 15

Reactive Power output of static reactive device generation: _ 5

Asynchronous generator nameplate (MVA @ rated pf): _ 40

0.85

Asynchronous CT ratio: _ 50005

Asynchronous high voltage CT ratio: _ _ 3005

CT remote substation bus _ _ 20005


72 of 129


Option 1a represents the simplest calculation for synchronous generators applying a phase distance relay (e.g., 21) directional toward the Transmission system.


Eq. (1) _

903 0.85

767.6


Eq. (2) 150%

1.50 767.6

1151.3


Eq. (3) 0.95 . .

0.95 345

22346.5

20.81

Apparent power (S):

Eq. (4) _

700.0 1151.3

1347.458.7°


Eq. (5) ∗

20.811347.4 58.7°


73 of 129


0.32158.7°Ω


Eq. (6)

0.32158.7°Ω

0.32158.7°Ω 25

8.03558.7°Ω


Eq. (7) 115%

8.03558.7° Ω1.15

6.987358.7° Ω

58.7°

Assume a Mho distance impedance relay with a maximum torque angle (MTA) set at 85˚,85°, then the maximum allowable impedance reach is:

Eq. (8) | |

cos

6.9873Ωcos 85.0° 58.7°

6.9873Ω0.896

7.79385.0° Ω


74 of 129


Option 1b represents a more complex, more precise calculation for synchronous generators applying a phase distance relay (e.g., 21) directional toward the Transmission system. This option requires calculating low‐side voltage taking into account voltage drop across the GSU transformer. Similarly these calculations may be applied to Option 7b for GSU transformers applying a phase distance relay (e.g., 21) directional toward the Transmission system.


Eq. (9) _

903 0.85

767.6


Eq. (10) 150%

1.50 767.6

1151.3

Convert Real Power, Reactive Power, and transformer reactance to per unit values on a 767.6 MVA base (MVAbase):


Eq. (11) _

700.0767.6

0.91 . .


Eq. (12)

1151.3767.6

1.5 . .


75 of 129


Transformer impedance (Xpu):

Eq. (13)

12.14%

767.6903

0.1032 . .


Eq. (14) sin| |

sin

0.91 0.10320.95 0.85

6.7°

Eq. (15)

| |cos cos 4

2

| |

|0.85| cos 6.7° |0.85| cos 6.7° 4 1.5 0.10322

| |

|0.85| 0.9931 √0.7225 0.9864 0.61922

| |

0.8441 1.15412

| | 0.9991 . .


76 of 129



Eq. (16) sin| |

sin

0.91 0.10320.9991 0.85

6.3°

Eq. (17)

| |cos cos 4

2

| |

|0.85| cos 6.3° |0.85| cos 6.3° 4 1.5 0.10322

| |

|0.85| 0.9940 √0.7225 0.9880 0.61922

| |

0.8449 1.15462

| | 0.9998 . .


Eq. (18) | |

0.9998 . . 345

22346.5

21.90

Apparent power (S):

Eq. (19) _

700.0 1151.3

1347.458.7° MVA


77 of 129



Eq. (20) ∗

21.901347.4 58.7°

0.35658.7°Ω


Eq. (21)

0.35658.7°Ω

0.35658.7°Ω 25

8.90058.7°Ω


Eq. (22) 115%

8.90058.7° Ω1.15

7.7458.7°Ω

58.7°


Eq. (23) | |

cos

7.74Ω

cos 85.0˚ 58.7°

7.74 Ωcos 85.0° 58.7°


78 of 129


7.74Ω0.8965

8.63385.0°Ω


Option 1c represents a more involved, more precise setting of the impedance element. This option requires determining maximum generator Reactive Power output during field‐forcing and the corresponding generator bus voltage. Once these values are determined, the remainder of the calculation is the same as Options 1a and 1b.




827.4

_ 0.989 _ 21.76 V


_ 700.0


79 of 129


Apparent power (S):

Eq. (24) _

700.0 827.4

1083.849.8° MVA


Eq. (25) 2

∗

_∗

21.761083.8 49.8°

0.43749.8°Ω


Eq. (26)

0.43749.8°Ω


80 of 129


0.43749.8°Ω 25

10.9249.8°Ω

To satisfy the 115% margin in the requirement in Options 1c and 7c:

Eq. (27) 115%

10.9249.8° Ω1.15

9.5049.8° Ω

49.8°


Eq. (28) | |

cos

9.50Ω

cos 85.0˚ 49.8°

9.50 Ωcos 85.0° 49.8°

9.50Ω0.8171

11.6385.0°Ω


Option 2a represents the simplest calculation for synchronous generators applying a phase time overcurrent (e.g., 50, 51, or 51V‐R) voltage restrained relay:


Eq. (29) _

903 0.85

767.6


81 of 129



Eq. (30) 150%

1.50 767.6

1151.3


Eq. (31) 0.95 . .

0.95 345

22346.5

20.81

Apparent power (S):

Eq. (32) _

700.0 1151.3

1347.458.7°


Eq. (33) √3

1347.41.73 20.81

37383


Eq. (34)

37383250005


82 of 129


7.477


Eq. (35) 115%

7.477 1.15

8.598


Option 2b represents a more complex calculation for synchronous generators applying a phase time overcurrent (e.g., 50, 51, or 51V‐R) voltage restrained relay:


Eq. (36) _

903 0.85

767.6


Eq. (37) 150%

1.50 767.6

1151.3

Convert Real Power, Reactive Power, and transformer reactance to per unit values on 767.6 MVA base (MVAbase).


Eq. (38) _

700.0767.6

0.91 . .


83 of 129



Eq. (39)

1151.3767.6

1.5 . .


Eq. (40)

12.14%

767.6903

0.1032 . .


Eq. (41) sin| |

sin

0.91 0.10320.95 0.85

6.7°

Eq. (42)

| |cos cos 4

2

| |

|0.85| cos 6.7° |0.85| cos 6.7° 4 1.5 0.10322


84 of 129


| |

|0.85| 0.9931 √0.7225 0.9864 0.61922

| |

0.8441 1.15412

| | 0.9991 . .


Eq. (43) sin| |

sin

0.91 0.10320.9991 0.85

6.3°

Eq. (44)

| |cos cos 4

2

| |

|0.85| cos 6.3° |0.85| cos 6.3° 4 1.5 0.10322

| |

|0.85| 0.9940 √0.7225 0.9880 0.61922

| |

0.8449 1.15462

| | 0.9998 . .


Eq. (45) | |

0.9998 . . 345

22346.5

21.90


85 of 129


Apparent power (S):

Eq. (46) _

700.0 1151.3

1347.458.7°


Eq. (47) √3

1347.41.73 21.90

35553


Eq. (48)

35553250005

7.111


Eq. (49) 115%

7.111 1.15

8.178


86 of 129


Option 2c represents a more involved, more precise setting of the overcurrent element for the phase time overcurrent (e.g., 50, 51, or 51V‐R) voltage restrained relay. This option requires determining maximum generator Reactive Power output during field‐forcing and the corresponding generator bus voltage. Once these values are determined, the remainder of the calculation is the same as Options 2a and 2b.




827.4

_ 0.989 _ 21.76


_ 700.0


87 of 129


Apparent power (S):

Eq. (50) _

700.0 827.4

1083.849.8° MVA


Eq. (51) √3 √3 _

1083.81.73 21.76

28790


Eq. (52)

28790250005


88 of 129


5.758

To satisfy the 115% margin in Option 2c:

Eq. (53) 115%

5.758 1.15

6.622


Option 3 represents the only calculation for synchronous generators applying a phase time overcurrent (e.g., 51V‐C) – voltage controlled relay (Enabled to operate as a function of voltage). Similarly, Option 6 uses the same calculation for asynchronous generators.


Eq. (54) 1.0 . .

1.0 345

22346.5

21.9

The voltage setting shall be set less than 75% of the generator bus voltage:

Eq. (55) 75%

21.9 0.75

16.429


This represents the calculation for an asynchronous generator (including inverter‐based installations) applying a phase distance relay (e.g., 21) – directional toward the Transmission system.


89 of 129



Eq. (56) _

40 0.85

34.0


Eq. (57) _ sin cos

40 sin cos 0.85

21.1


Eq. (58) 1.0 . .

1.0 345

22346.5

21.9

Apparent power (S):

Eq. (59)

34.0 21.1

40.031.8°


Eq. (60) ∗

21.940.0 31.8°

11.9931.8°Ω


90 of 129



Eq. (61) _

11.9931.8°Ω

11.9931.8°Ω 5

59.9531.8°Ω


Eq. (62) 130%

59.9531.8° Ω1.30

46.1231.8° Ω

31.8°


Eq. (63) | |

cos

46.12Ωcos 85.0° 31.8°

46.12Ω0.599

77.085.0°Ω


91 of 129


This represents the calculation for three asynchronous generators applying a phase time

overcurrent (e.g., 50, 51, or 51V‐R) – voltage-restrained relay. In this application it was assumed that 20 Mvar of total static compensation was added.


Eq. (64) 3 _

3 40 0.85

102.0


Eq. (65) _ 3 _ sin cos

15 5 3 40 sin cos 0.85

83.2


Eq. (66) 1.0 . .

1.0 345

22346.5

21.9

Apparent power (S):

Eq. (67)

102.0 83.2

131.639.2°


Eq. (68) ∗

√3


92 of 129


131.6 39.2°1.73 21.9

3473 39.2°


Eq. (69) _

3473 39.2°50005

3.473 39.2°


Eq. (70) 130%

3.473 39.2° 1.30

4.52 39.2°

Example Calculations: Options 7a and 10Option 5b

ThisSimilarly to Option 5a, this example represents the calculation for a mixture ofthree asynchronous (i.e., Option 10) and synchronous (i.e., Option 7a) generation (including inverter-based

installations)generators applying a phase distanceovercurrent (e.g., 50, 51, or 51V‐R) relay (21) –

directional toward the Transmission system.. In this application it was assumed that 20 Mvar of total static compensation was added.


Real Power output ( ):P):

Eq. (71) _ 3 _

3 40 0.85

102.0


93 of 129



Eq. (72) _ 3 _ sin cos

15 5 3 40 sin cos 0.85

83.2

Option 5b, Table 1 – Bus Voltage, calls for a 1.0 per unit of the high‐side nominal voltage for the generator bus voltage (Vgen):

Eq. (73) 1.0 . .

1.0 345

22346.5

21.9

Apparent power (S):

Eq. (74)

102.0 83.2

131.639.2°


Eq. (75) ∗

√3

131.6 39.2°1.73 21.9

3473 39.2°


Eq. (76) _

3473 39.2°50005


94 of 129


3.473 39.2°

To satisfy Option 5b, the overcurrent element shall not infringe upon the resource capability (including the Mvar output of the resource and any static or dynamic reactive power devices) with worst case documented tolerances applied between the maximum resource capability and the overcurrent element (see Figure A).


These examples represent the calculation for a mixture of asynchronous (i.e., Option 10) and synchronous (i.e., Option 7a) generation (including inverter‐based installations) applying a phase distance relay (e.g., 21) directional toward the Transmission system. In this application it was assumed 20 Mvar of total static compensation was added.


Real Power output ( ):

Eq. (77) _

903 0.85

767.6

Reactive Power output ( ):

Eq. (7278) 150%

1.50 767.6

1151.3


Eq. (7379) _

700.0 1151.3


95 of 129


Asynchronous Generation (Option 10)



Eq. (7480) 3 _

3 40 0.85

102.0


Eq. (7581) _ 3 _ sin cos

15 5 3 40 sin cos 0.85

83.2


Eq. (7682)

102.0 83.2

Options 7a and 10, Table 1 – Bus Voltage, Option 7a specifies 0.95 per unit of the high‐side nominal voltage for the generator bus voltage and Option 10 specifies 1.0 per unit of the high‐side nominal voltage for generator bus voltage. Due to the presence of the synchronous generator, the 0.95 per unit bus voltage will be used as (Vgen) as it results in the most conservative voltage:

Eq. (7783) 0.95 . .

0.95 345

22346.5

20.81

Apparent power (S) accounted for 115% margin requirement for a synchronous generator and 130% margin requirement for an asynchronous generator:

Eq. (7884) 115% _ 130%

1.15 700.0 1151.3 1.30 102.0 83.2


96 of 129


1711.856.8°


Eq. (7985) ∗

20.811711.8 56.8°

0.252756.8°Ω


Eq. (8086)

0.252756.8°Ω

0.252756.8°Ω 25

6.3256.8°Ω

No additional margin is needed; therefore, the margin is 100% because the synchronous apparent power has been multiplied by 1.15 (115%) and the asynchronous apparent power has been multiplied by 1.30 (130%) in Equation 8584 to satisfy the margin requirements in Options 7a and 10:.

Eq. (8187) 100%

6.3256.8° Ω1.00

6.3256.8° Ω

56.8°


Eq. (8288) | |

cos


97 of 129


6.32Ωcos 85.0° 56.8°

6.32Ω0.881

7.1785.0°Ω


Options 8a and 9a represents the simplest calculation for synchronous generators applying a phase time overcurrent (e.g., 50, 51, or 67) relay. The following uses the GENSynch_nameplate value to represent an “aggregate” value to illustrate the option:


Eq. (8389) _

903 0.85

767.6


Eq. (8490) 150%

1.50 767.6

1151.3

Options 8a and 9a, Table 1 – Bus Voltage, calls for a generator bus voltage corresponding to 0.95 per unit of the high‐side nominal voltage times the turns ratio of the generator step‐up transformer generator bus voltage (Vgen):

Eq. (8591) 0.95 . .

0.95 345

22346.5

20.81


98 of 129


Apparent power (S):

Eq. (8692) _

700.0 1151.3

1347.458.7°


Eq. (8793) √3

1347.41.73 20.81

37383


Eq. (8894)

37383250005

7.477


Eq. (8995) 115%

7.477 1.15

8.598


Options 8b and 9b represents a more complexprecise calculation for synchronous generators applying a phase time overcurrent (e.g., 50, 51, or 67) relay. The following uses the GENSynch_nameplate value to represent an “aggregate” value to illustrate the option:


99 of 129



Eq. (9096) _

903 0.85

767.6


Eq. (9197) 150%

1.50 767.6

1151.3

Convert Real Power, Reactive Power, and transformer reactance to per unit values on 767.6 MVA base (GSU Transformer MVAbase).


Eq. (9298) _

700.0767.6

0.91 . .


Eq. (9399)

1151.3767.6

1.5 . .


Eq. (94100)


100 of 129


12.14%

767.6903

0.1032 . .


Eq. (95101) sin

| |

sin

0.91 0.10320.95 0.85

Eq. (102)

| |cos cos 4

2

| |

|0.85| cos 6.7° |0.85| cos 6.7° 4 1.5 0.10322

| |

|0.85| 0.9931 √0.7225 0.9864 0.61922

| |

0.8441 1.15412

| | 0.9991 . .


Eq. (97103) sin

| |

sin

0.91 0.10320.9991 0.85

6.3°


101 of 129


Eq. (104)

| |cos cos 4

2

| |

|0.85| cos 6.3° |0.85| cos 6.3° 4 1.5 0.10322

| |

|0.85| 0.9940 √0.7225 0.9880 0.61922

| |

0.8449 1.15462

| | 0.9998 . .


Eq. (99105)

| |

0.9998 . . 345

22346.5

21.90

Apparent power (S):

Eq. (100106)

_

700.0 1151.3

1347.458.7°


Eq. (101107) √3

1347.41.73 21.90

35553


102 of 129



Eq. (102108)

35553250005

7.111


Eq. (103109)

115%

7.111 1.15

8.178


This example represents the calculation for a mixture of asynchronous and synchronous generators applying a phase time overcurrent (e.g., 50, 51, or 67) relays. In this application it was assumed 20 Mvar of total static compensation was added. The current transformers (CT) are located on the low‐side of the GSU transformer.

Synchronous Generation (Options 8a and 9a)



Eq. (104110)

_

903 .85

767.6


103 of 129


Reactive Power output (QSynch):

Eq. (105111)

150%

1.50 767.6

1151.3


Eq. (106112)

_

700.0 1151.3

1347.458.7°

Option 8a, Table 1 – Bus Voltage calls for a 0.95 per unit of the high‐side nominal voltage as a basis for generator bus voltage (Vgen):

Eq. (107113)

0.95 . .

0.95 345

22346.5

20.81

Primary current (Ipri‐sync):

Eq. (108114)

115% ∗

√3

1.15 1347.4 58.7°1.73 20.81

43061 58.7°


104 of 129


Asynchronous Generation (Options 11 and 12)



Eq. (109115)

3 _

3 40 0.85

102.0


Eq. (110116)

_ _ sin cos

15 5 3 40 sin cos 0.85

83.2

Option 11, Table 1 – Bus Voltage, calls for a 1.0 per unit of the high‐side nominal voltage for the generator bus voltage (Vgen), however due to the presence of synchronous generator 0.95 per unit bus voltage will be used:

Eq. (111117)

0.95 . .

0.95 345

22346.5

20.81


Eq. (112118)

130%

1.30 102.0 83.2

171.139.2°


105 of 129


Primary current (Ipri‐async):

Eq. (113119) √3

171.1 39.2°1.73 20.81

4755 39.2°


Eq. (114120)

43061 58.7°250005

4755 39.2°250005

9.514 56.8°

No additional margin is needed; therefore, the margin is 100% because the synchronous apparent power has been multiplied by 1.15 (115%) in Equation 94114 and the asynchronous apparent power has been multiplied by 1.30 (130%) in Equation 98:118.

Eq. (115121)

100%

9.514 56.8° 1.00

9.514 56.8°


This example uses Option 15b as a simulation example for a synchronous generator applying a phase time overcurrent relay. (e.g., 50, 51, or 67). In this application the same synchronous generator is modeled as for Options 1c, 2c, and 7c. The CTs are located on the low‐side of the GSU transformer.

The generator Reactive Power and generator bus voltage are determined by simulation. The maximum Reactive Power output on the low‐side of the GSU transformer, during field‐forcing, is used since this value will correspond to the highest current. The corresponding generator bus voltage is also used in the calculation. Note that although the excitation limiter


106 of 129


reduces the field, the duration of the Reactive Power output achieved for this condition is sufficient to operate a phase overcurrent relay.

In this simulation the following values are derived:The generator Reactive Power and generator bus voltage are determined by simulation. The maximum Reactive Power output on the low-side of the GSU transformer during field-forcing is used as this value will correspond to the highest current. The corresponding generator bus voltage is also used in the calculation. Note that although the excitation limiter reduces the field, the duration of the Reactive Power output achieved for this condition is sufficient to operate a phase overcurrent relay.

827.4

_ 0.989 21.76


700.0


107 of 129


Apparent power (S):

Eq. (116122) _

700.0 827.4

1083.849.8°


Eq. (117123) √3 √3 _

1083.81.73 21.76

28790


Eq. (118124)

28790250005


108 of 129


5.758

To satisfy the 115% margin in Options 8c and 9c:

Eq. (119125) 115%

5.758 1.15

6.622


This example represents the calculation for three asynchronous generators (including inverter‐based installations) applying a phase distance relay (e.g., 21) – directional toward the Transmission system. In this application it was assumed 20 Mvar of total static compensation was added.


Eq. (120126)

3 _

3 40 0.85

102.0


Eq. (121127)

_ 3 _ sin cos

15 5 3 40 sin cos 0.85

83.2


Eq. (122128)

1.0 . .


109 of 129


1.0 345

22346.5

21.9

Apparent power (S):

Eq. (123129)

102.0 83.2

131.639.2°


Eq. (124130) ∗

21.9131.6 39.2°

3.64439.2°Ω


Eq. (125131)

_

3.64439.2°Ω

3.64439.2°Ω 5

18.2239.2°Ω


Eq. (126132) 130%

18.2239.2° Ω1.30


110 of 129


14.0239.2° Ω

39.2°


Eq. (127133)

| |

cos

14.02Ωcos 85.0° 39.2°

14.02Ω0.6972

20.1185.0° Ω


Option 11 represents the calculation for a GSU transformer applying a phase time overcurrent (e.g., 50 or 51) relay connected to three asynchronous generators. Similarly, these calculations can be applied to Option 12 for a phase directional time overcurrent relay (e.g., 67) directional toward the Transmission system. In this application it was assumed 20 Mvar of total static compensation was added.


Eq. (128134)

3 _

3 40 0.85

102.0


Eq. (129135)

_ 3 _ sin cos

15 5 3 40 sin cos 0.85


111 of 129


83.2


Eq. (130136)

1.0 . .

1.0 345

22346.5

21.9

Apparent power (S):

Eq. (131137)

102.0 83.2

131.639.2°


Eq. (132138)

∗

√3

131.6 39.2°1.73 21.9

3473 39.2°


Eq. (133139) _

3473 39.2°50005

3.473 39.2°


112 of 129


To satisfy the 130% margin in Options 11 and12:

Eq. (134140)

130%

3.473 39.2° 1.30

4.515 39.2°


Option 13a for the UAT assumes that the maximum nameplate rating of the winding is utilized for the purposes of the calculations and the appropriate voltage. Similarly, Option 13b uses the measured current while operating at the maximum gross MW capability reported to the Transmission Planner.


Eq. (135141) √3

601.73 13.8

2510.2


Eq. (136142)

2510.250005

2.51A

To satisfy the 150% margin in Options 13a:

Eq. (137143)

150%


113 of 129


2.51 1.50

3.77


Option 14a represents the calculation for a synchronous generation Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant that connected to synchronous generation. In this example, the Element is applyingprotected by a phase distance (e.g., 21) relay directional toward the Transmission system. The CTs are located on the high‐side of the GSU transformer.


Eq. (138144)

_

903 0.85

767.6


Eq. (139145)

120%

1.20 767.6

921.1

Option 14a, Table 1 – Bus Voltage, calls for a 0.85 per unit of the high-sideline nominal voltage for the GSU transformer voltage (Vnom):

Eq. (140146)

0.85 . .

0.85 345

293.25


114 of 129


Apparent power (S):

Eq. (141147)

_

700.0 921.1

1157.052.77°

52.77°


Eq. (142148) ∗

293.251157.0 52.77°

74.33552.77° Ω


Eq. (143149)

_

_

74.33552.77° Ω

74.33552.77° Ω 0.2

14.86752.77° Ω


Eq. (144150) 115%

14.86752.77° Ω1.15

12.92852.77° Ω

52.77°


115 of 129



Eq. (145151)

| |

cos

12.928Ωcos 85.0° 52.77°

12.928Ω0.846

15.28385.0° Ω


Option 14b represents the simulation for a synchronous generation Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant thatconnected to synchronous generation. In this example, the Element is applyingprotected by a phase distance (e.g., 21) relay directional toward the Transmission system. The CTs are located on the high‐side of the GSU transformer.




703.6


116 of 129


_ 0.908 313.3


700.0

Apparent power (S):

Eq. (146152)

_

700.0 703.6

992.545.1°

45.1°


Eq. (147153)

2

∗

_∗

313.3992.5 45.1°


117 of 129


98.9045.1°Ω


Eq. (148154)

_

_

98.9045.1°Ω

98.9045.1°Ω 0.2

19.7845.1°Ω


Eq. (149155) 115%

19.7845.1° Ω1.15

17.2045.1° Ω

45.1°


Eq. (150156)

| |

cos

17.20Ωcos 85.0° 45.1°

17.20Ω0.767

22.4285.0° Ω


118 of 129


Options 15a and 16a represent the calculation for a synchronous generation Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. connected to synchronous generation. Option 15a represents applying a phase time overcurrent relay (e.g., 51) and/or Phasephase instantaneous overcurrent supervisory elements (e.g., 50) associated with current‐based, communication‐assisted schemes where the scheme is capable of tripping for loss of communications – installed on the high‐side of the GSU transformer. and remote end of the line. Option 16a represents applying a phase directional time overcurrent relay or Phase

directionalinstantaneous overcurrent supervisory elements (element (e.g., 67) associated with current‐based, communication‐assisted schemes where the scheme is capable of tripping for loss of communications – directional toward the Transmission system– installed on the high‐side of the GSU and at the remote end of the line and/or a phase time directional overcurrent relay (e.g., 67) directional toward the Transmission system installed on the high‐side of the GSU transformer and remote end of the line. This example uses Option 15a as an example, where PTs and CTs are located in the high-side of the GSU transformer.Example calculations are provided for the case, where potential transformers (PT) and current transformers (CT) are located at the high‐side of the GSU transformer. The 0.85 per unit of the line nominal voltage at the relay location will be at the high‐side of the GSU transformer. Example calculations are also provided for the case where PTs and CTs are located at the remote end of the line and the 0.85 per unit of the line nominal voltage will be at the remote bus location.

Calculations at the high-side of the GSU transformer.


Eq. (151157)

_

903 0.85

767.6


Eq. (152158)

120%

1.20 767.6

921.12


119 of 129


Option 15a, Table 1 – Bus Voltage, calls for a 0.85 per unit of the high-sideline nominal voltage:

Eq. (153159)

0.85 . .

0.85 345

293.25

Apparent power (S):

Eq. (154160)

_

700.0 921.12

115752.8°


Eq. (155161)

∗

√3

1157∠ 52.8°1.73 293.25

2280.6∠ 52.8°


Eq. (156162) _

2280.6∠ 52.8°20005

5.701∠ 52.8°

To satisfy the 115% margin in Options 15a and 15b16a:

Eq. (157163)

115%


120 of 129


5.701∠ 52.8° 1.15

6.56∠ 52.8°

Calculations at the remote end of the line from the plant.


Eq. (164) _

903 0.85

767.6


Eq. (165) 120%

1.20 767.6

921.12

Option 15a and 16a, Table 1 – Bus Voltage, calls for a 0.85 per unit of the line nominal voltage at the relay location, in this example the relay location is at the remote substation bus.

Eq. (166) _ _ 0.85 . .

_ _ 0.85 345

_ _ 293.25

Apparent power (S):

Eq. (167) _

700.0 921.12

115752.8°


Eq. (168) ∗

√3 _ _


121 of 129


1157∠ 52.8°1.73 293.25

2280.6∠ 52.8°


Eq. (169) _ _

2280.6∠ 52.8°20005

5.701∠ 52.8°


Eq. (170) 115%

5.701∠ 52.8° 1.15

6.56∠ 52.8°


122 of 129


Options 15b and 16b represent the calculation for a synchronous generation Elements that connect a GSU transformer to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. connected to synchronous generation. Option 15b represents applying a phase time overcurrent relay (e.g., 51) and/or Phasephase instantaneous overcurrent supervisory elements (e.g., 50) associated with current‐based, communication‐assisted schemes where the scheme is capable of tripping for loss of communications – installed on the high‐side of the GSU transformer. and remote end of the line. Option 16b represents applying a phase directional time overcurrent relay or Phase

directionalinstantaneous overcurrent supervisory elements (element (e.g., 67) associated with current‐based, communication‐assisted schemes where the scheme is capable of tripping for loss of communications – directional toward the Transmission system– installed on the high‐side of the GSU and at the remote end of the line and/or a phase directional time overcurrent relay (e.g., 67) directional toward the Transmission system installed on the high‐side of the GSU and remote end of the line.

This example uses Option 15b as a simulation exampleExample calculations are provided for the case, where PTs and CTs are located at the remote end of the line from the plant. The 0.85 per unit of the line nominal voltage is applied at the remote end of the line.

The Reactive Power flow and high‐side bus voltage are determined by simulation. The maximum Reactive Power output on the in the high‐side of the GSU transformer during field‐forcing is used as this value will correspond to the lowest apparent impedance. The corresponding high‐side bus voltage is also used in the calculation. Note that although the excitation limiter reduces the field, the duration of the Reactive Power output achieved for this condition is sufficient to operate a phase overcurrent relay.

The Reactive Power flow and high‐side bus voltage are determined by simulation. The maximum Reactive Power output on the high-side of the GSU transformer during field-forcing is used as this value will correspond to the lowest apparent impedance. The corresponding high-side bus voltage is also used in the calculation. Note that although the excitation limiter reduces the field, the duration of the Reactive Power output achieved for this condition is sufficient to operate a phase overcurrent relay.


703.6

_ 0.908 313.3


700.0


123 of 129


Apparent power (S):

Eq. (158171)

_

700.0 703.6

992.545.1°


Eq. (159172)

∗

√3

∗

√3 _

992.5 45.1°1.73 313.3

1831.2∠ 45.1°


Eq. (160173) _


124 of 129


1831.2∠ 45.1°20005

4.578∠ 45.1°


Eq. (161174)

115%

4.578∠ 45.1° 1.15

5.265∠ 45.1°


Option 17 represents the calculation for three asynchronous generation Elements that connect a GSU transformer for three asynchronous generators to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant that is applying a phase distance relay (e.g., 21) - directional toward the Transmission system. In this application it was assumed 20 Mvar of total static compensation was added.


Eq. (162175)

3 _

3 40 0.85

102.0


Eq. (163176)

_

3 _ sin cos

15 5 3 40 sin cos 0.85

83.2


125 of 129


Option 17, Table 1 – Bus Voltage, calls for a 1.0 per unit of the high-sideline nominal voltage for the bus voltage (Vbus):

Eq. (164177)

1.0 . .

1.0 345

345.0

Apparent power (S):

Eq. (165178)

102.0 83.2

131.639.2°


Eq. (166179) ∗

345.0131.6 39.2°

904.439.2°Ω


Eq. (167180)

_ _

_

904.439.2°Ω

904.439.2°Ω 0.03

27.1339.2°Ω


126 of 129



Eq. (168181) 130%

27.1339.2° Ω1.30

20.86939.2° Ω

39.2°

Assume a Mho distance impedance relay with a maximum torque angle (MTA) set at 85˚,85°, and then the maximum allowable impedance reach is:

Eq. (169182)

| |

cos

20.869Ωcos 85.0° 39.2°

20.869Ω0.697

29.94185.0° Ω


Option 18 represents the calculation for three generationrelays on Elements that connect a GSU transformer for three asynchronous generators to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant that is . Option 18 represents applying a phase time overcurrent (e.g., 51) relay connected to three

asynchronous generators. and/or phase instantaneous overcurrent supervisory elements (e.g., 50) associated with current‐based, communication‐assisted schemes where the scheme is capable of tripping for loss of communications installed on the high‐side of the GSU transformer and remote end of the line.

Similarly, Option 19 may also be applied here for the phase directional time overcurrent relays (e.g., 67) directional toward the Transmission system for Elements that connect a GSU transformer and remote end of the line to the Transmission system that are used exclusively to export energy directly from a BES generating unit or generating plant. In this application it was assumed 20 Mvar of total static compensation was added.


127 of 129



Eq. (170183)

3 _

3 40 0.85

102.0


Eq. (171184)

_

3 _ sin cos

15 5 3 40 sin cos 0.85

83.2

Options 18 and 19, Table 1 – Bus Voltage, calls for a 1.0 per unit of the high-sideline nominal voltage (Vbus):

Eq. (172185)

1.0 . .

1.0 345

345

Apparent power (S):

Eq. (173186)

102.0 83.2

131.639.2°


Eq. (174187)

∗

√3

131.6 39.2°1.73 345


128 of 129


220.5 39.2°


Eq. (175188) _ _

220.5 39.2°3005

3.675 39.2°

To satisfy the 130% margin in Options 18 and 19:

Eq. (176189)

130%

3.675 39.2° 1.30

4.778 39.2°

End of calculations

129 of 129

Rationale: During development of this standard, text boxes were embedded within the standard to explain the rationale for various parts of the standard. Upon BOT approval, the text from the rationale text boxes was moved to this section. Rationale for R1: Requirement R1 is a risk‐based requirement that requires the responsible entity to be aware of each protective relay subject to the standard and applies an appropriate setting based on its calculations or simulation for the conditions established in Attachment 1. The criteria established in Attachment 1 represent short‐duration conditions during which generation Facilities are capable of providing system reactive resources, and for which generation Facilities have been historically recorded to disconnect, causing events to become more severe. The term, “while maintaining reliable fault protection” in Requirement R1 describes that the responsible entity is to comply with this standard while achieving their desired protection goals. Refer to the Guidelines and Technical Basis, Introduction, for more information.

Implementation Plan Project 2016-04 – Modifications to PRC-025-1

Requested Approvals PRC‐025‐2 – Generator Relay Loadability

Requested Retirements PRC‐025‐1 – Generator Relay Loadability

Prerequisite Approvals None.

Applicable Entities* Generator Owner Transmission Owner Distribution Provider

*See the proposed standard for detailed applicability for functional entities and Facilities.

Terms in the NERC Glossary of Terms No definitions are proposed as a part of this standard.

Background The Reliability Standard PRC‐025‐1 went into effect in the United States on October 1, 2014 under a phased implementation plan based on two time frames. The first timeframe was provided to the Generator Owner, Transmission Owner, or Distribution Provider to apply settings to its existing load‐responsive protective relays that are capable of meeting the standard while maintaining reliable fault protection. The second and extended timeframe was provided to the Generator Owner, Transmission Owner, or Distribution Provider that determined its existing load‐responsive protective relays require replacement or removal. The PRC‐025‐1 standard drafting team recognized that it may be necessary to replace a legacy load‐responsive protective relay with a modern advanced‐technology relay that can be set using functions such as load encroachment or that removal of the load‐responsive protective relay is the best alternative to satisfy the entity’s protection criteria and meet the requirements of PRC‐025‐1.

General Considerations The PRC‐025‐2 standard drafting team considered the scope of the proposed revisions and the timing for regulatory approvals with respect to the version one enforcement dates. The first U.S. enforcement date of October 1, 2019 applies to load‐responsive protective relays where the applicable entity will be making a setting change to meet the setting criteria of the standard while maintaining reliable fault protection. The second U.S. enforcement date of October 1, 2021 applies to load‐responsive protective relays where

Agenda Item 7(iii)Standards CommitteeJuly 19, 2017

Implementation Plan (Draft 1: PRC‐025‐2) Project 2016‐04 – Modifications to PRC‐025‐1 | July 6, 2017 2

the applicable entity will be removing or replacing the relay to meet the setting criteria of the standard while maintaining reliable fault protection. The PRC‐025‐2 Implementation Plan reflects consideration of the following:

The proposed Option 5b reduces the implementation burden to the applicable entities. The proposed revisions to Options 14a, 14b, 15a, 15b, 16a, 16b, 17, 18, and 19 may give reason for

entities to re‐evaluate their settings for load‐responsive protective relays. A few proposed Option(s) now include the 50 element.

Effective Date

PRC‐025‐2 Where approval by an applicable governmental authority is required, the standard shall become effective on the first day of the first calendar quarter after the effective date of the applicable governmental authority’s order approving the standard, or as otherwise provided for by the applicable governmental authority. Where approval by an applicable governmental authority is not required, the standard shall become effective on the first day of the first calendar quarter after the date the standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that jurisdiction.

Effective Date and Phased-In Compliance Dates

Load‐responsive protective relays subject to the standard Each Generator Owner, Transmission Owner, or Distribution Provider shall not be required to comply with Requirement R1 until the following dates after the effective date of Reliability Standard PRC‐025‐2:

Requirement Applicability Implementation Date

R1

Each Generator Owner, Transmission Owner, and Distribution Provider shall apply settings that are in accordance with PRC‐025‐2 – Attachment 1: Relay Settings, on each load‐responsive protective relay while maintaining reliable fault protection.

Where determined by the Generator Owner, Transmission Owner, or Distribution Provider that replacement or removal is not necessary, 12 months after the effective date of Reliability Standard PRC‐025‐2

Where determined by the Generator Owner, Transmission Owner, or Distribution Provider that replacement or removal is necessary, 36 months after the effective date of Reliability Standard PRC‐025‐2

Load‐responsive protective relays which become applicable to the standard

Each Generator Owner, Transmission Owner, or Distribution Provider that owns load‐responsive protective relays that become applicable to this standard, not because of the actions of itself including but

Implementation Plan (Draft 1: PRC‐025‐2) Project 2016‐04 – Modifications to PRC‐025‐1 | July 6, 2017 3

not limited to changes in NERC Registration Criteria or Bulk Electric System (BES) definition, shall not be required to comply with Requirement R1 until the following dates:

Requirement Applicability Implementation Date

R1

Each Generator Owner, Transmission Owner, and Distribution Provider shall apply settings that are in accordance with PRC‐025‐2 – Attachment 1: Relay Settings, on each load‐responsive protective relay while maintaining reliable fault protection.

Where determined by the Generator Owner, Transmission Owner, or Distribution Provider that replacement or removal is not necessary, 60 months beyond the date the load‐responsive protective relays become applicable to the standard

Where determined by the Generator Owner, Transmission Owner, or Distribution Provider that replacement or removal is necessary, 84 months beyond the date the load‐responsive protective relays become applicable to the standard

Retirement Date

PRC‐025‐1 Reliability Standard PRC‐025‐1 shall be retired immediately prior to the effective date of PRC‐025‐2 in the particular jurisdiction in which the revised standard is becoming effective.

Phased-In Retirement

None. Implementation Plan for Definitions

No definitions are proposed as a part of this standard.

Violation Risk Factor and Violation Severity Level Justifications PRC-025-2 – Generator Relay Loadability

Violation Risk Factor and Violation Severity Level Justifications This document provides the drafting team’s justification for assignment of violation risk factors (VRFs) and violation severity levels (VSLs) for each requirement in: PRC‐025 – Generator Relay Loadability. Note that no Requirement, Measure, or VRF/VSL changes have been made in this proposed PRC‐025‐2 Reliability Standard.

Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of requirements in FERC‐approved Reliability Standards, as defined in the ERO Sanction Guidelines.

The Reliability Coordination Standard Drafting Team (SDT) applied the following NERC criteria and FERC Guidelines when proposing VRFs and VSL for the requirements under this project.

NERC Criteria – Violation Risk Factors High Risk Requirement A requirement that, if violated, could directly cause or contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.

Medium Risk Requirement A requirement that, if violated, could directly affect the electrical state or the capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric system. However, violation of a medium risk requirement is unlikely to lead to bulk electric system instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric system. However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or

Agenda Item 7(iv)Standards CommitteeJuly 19, 2017

VRF and VSL Justifications (Draft 1: PRC‐025‐2) Project 2016‐04 Modifications to PRC‐025‐1 | July 6, 2017 2

restoration conditions anticipated by the preparations, to lead to bulk electric system instability, separation, or cascading failures, nor to hinder restoration to a normal condition. Lower Risk Requirement A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric system; or, a requirement that is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric system. A planning requirement that is administrative in nature. FERC Violation Risk Factor Guidelines The SDT also considered consistency with the FERC Violation Risk Factor Guidelines for setting VRFs:1 Guideline 1 – Consistency with the Conclusions of the Final Blackout Report The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical critical impact on the reliability of the Bulk‐Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could severely affect the reliability of the Bulk‐Power System:2

Emergency operations

Vegetation management

Operator personnel training

Protection systems and their coordination

Operating tools and backup facilities

Reactive power and voltage control

System modeling and data exchange

Communication protocol and facilities

Requirements to determine equipment ratings

Synchronized data recorders

1 North American Electric Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120 FERC ¶ 61,145 (2007) (“VRF Rehearing Order”). 2 Id. at footnote 15.


Clearer criteria for operationally critical facilities

Appropriate use of transmission loading relief Guideline 2 – Consistency within a Reliability Standard The Commission expects a rational connection between the sub‐Requirement Violation Risk Factor assignments and the main Requirement Violation Risk Factor assignment. Guideline 3 – Consistency among Reliability Standards The Commission expects the assignment of Violation Risk Factors corresponding to Requirements that address similar reliability goals in different Reliability Standards would be treated comparably. Guideline 4 – Consistency with NERC’s Definition of the Violation Risk Factor Level Guideline (4) was developed to evaluate whether the assignment of a particular Violation Risk Factor level conforms to NERC’s definition of that risk level. Guideline 5 – Treatment of Requirements that Co-mingle More Than One Obligation Where a single Requirement co‐mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability Standard. NERC Criteria – Violation Severity Levels Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance, and may have only one, two, or three VSLs. Violation severity levels should be based on the guidelines shown in the table below:


Missing a minor element (or a small percentage) of the required performance The performance or product measured has significant value as it almost meets the full intent of the requirement.

Missing at least onesignificant element (or a moderate percentage) of the required performance. The performance or product measured still has significant value in meeting the intent of the requirement.

Missing more than one significant element (or is missing a high percentage) of the required performance or is missing a single vital component. The performance or product has limited value in meeting the intent of the requirement.

Missing most or all of the significant elements (or a significant percentage) of the required performance. The performance measured does not meet the intent of the requirement or the product delivered cannot be used in meeting the intent of the requirement.


FERC Order of Violation Severity Levels FERC’s VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard meet the FERC Guidelines for assessing VSLs: Guideline 1 – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current Level of Compliance Compare the VSLs to any prior levels of non‐compliance and avoid significant changes that may encourage a lower level of compliance than was required when levels of non‐compliance were used. Guideline 2 – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of Penalties A violation of a “binary” type requirement must be a “Severe” VSL.

Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance. Guideline 3 – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement VSLs should not expand on what is required in the requirement.

Guideline 4 – Violation Severity Level Assignment Should Be Based on A Single Violation, Not on A Cumulative Number of Violations . . . unless otherwise stated in the requirement, each instance of non‐compliance with a requirement is a separate violation. Section 4 of the Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.


VRF and VSL Justifications

VRF Justifications – PRC‐025‐2, R1

Proposed VRF High

NERC VRF Discussion

A Violation Risk Factor of High is consistent with the NERC VRF definition. Failure by an entity to apply load‐responsive protective relay settings in accordance with PRC‐025‐2, Attachment 1; Relay Settings, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.

The unnecessary tripping of protective relays on generators has often been determined to have expanded the scope and/or extended the duration of disturbances of the past 25 years. This was also noted to be a serious issue in the August 2003 “blackout” in the northeastern North American continent.


Guideline 1‐ Consistency w/ Blackout Report:

The blackout report and subsequent technical analysis noted that generators tripped for the conditions being addressed by this standard, increasing the severity of the blackout.


Guideline 2‐ Consistency within a Reliability Standard:

Only one requirement is provided and is proposed for a “High” VRF.


Guideline 3‐ Consistency among Reliability Standards:

Requirement R1, criterion 6 of PRC‐023‐2 – Transmission Relay Loadability addresses similar concerns regarding Transmission lines and is also a “High” VRF.


Guideline 4‐ Consistency with NERC Definitions of VRFs:

The results of the reports into the August 2003 blackout, as well as the subsequent analysis, clearly demonstrate that violating this requirement, under abnormal or emergency conditions, could cause or contribute to cascading failures on the Bulk Electric System.


VRF Justifications – PRC‐025‐2, R1

Proposed VRF High


Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation:

This requirement does not co‐mingle more than one obligation.

Proposed VSLs for PRC‐025‐2, R1

R1 Lower Moderate High Severe

R1 N/A N/A N/A

The Generator Owner, Transmission Owner, or Distribution Provider did not apply settings in accordance with PRC‐025‐2 – Attachment 1: Relay Settings, on an applied load‐responsive protective relay.

VSL Justifications – PRC‐025‐2, R1

NERC VSL Guidelines The NERC VSL guidelines are satisfied by identifying noncompliance based on “pass‐fail” or a binary condition. The entity either “applied” or “did not apply” the setting(s) in accordance with Attachment 1: Relay Settings; therefore, the Violation Severity Level must be designated Severe.

FERC VSL G1


The VSL is not changing from the current approved version; therefore, there is no lowering the current level of compliance.


Proposed VSLs for PRC‐025‐2, R1

FERC VSL G2




Guideline 2a:

The single proposed VSL is a binary VSL (pass‐fail). The entity either “applied” or “did not apply” the setting(s) in accordance with Attachment 1: Relay Settings; therefore, the VSL is proposed to be “Severe” in accordance with the criteria for binary VSLs.

Guideline 2b:

The proposed VSL is clear and unambiguous.

FERC VSL G3


The proposed VSL is consistent with the corresponding requirement.

FERC VSL G4


The proposed VSL addresses each individual instance of violations by basing the violations on failing to apply the setting(s) on “an applied load‐responsive protective relay” in accordance with Attachment 1: Relay Settings.


Project 2017-03 FAC-008-3 Periodic Review

Team Recommendation Action Appoint members, chair, and vice chair to the periodic review team (PRT) for Project 2017-03 FAC-008-3 Periodic Review, as recommended by NERC staff. Background From May 10 – 23, 2017, NERC solicited nominations for volunteers to serve on a periodic review team (PRT) for FAC-008-3 – Facility Ratings. NERC staff received twelve (12) nominations from industry professionals and is recommending eight (8) individuals with the requisite background, experience, and skills necessary for conducting a review of the Reliability Standard. The PRT will incorporate the output of the 2016 Standing Review Team (SRT) – Standards Grading in its review. The periodic review will also include background information, along with any associated worksheets or reference documents, to guide a comprehensive review that results in a recommendation that the Reliability Standard should be: (1) reaffirmed as is (i.e., no changes needed); (2) revised (which may include revising or retiring one or more requirements); or (3) withdrawn.


Project 2017-04 INT Standards Periodic Review

Team Recommendation Action Appoint members, chair, and vice chair to the periodic review team (PRT) for Project 2017-04 Periodic Review, as recommended by NERC staff. Background From May 10 – 23, 2017, NERC solicited nominations for volunteers to serve on a PRT for Reliability Standards INT-004-3.1, INT-006-4, INT-009-2.1, and INT-010-2.1 – Interchange and Coordination. NERC staff received ten (10) nominations from industry professionals and recommends eight (8) individuals with the requisite background, experience, and skills necessary for membership on the PRT reviewing the Reliability Standards. The PRT will incorporate 2016 Standing Review Team – Standards Grading results during its review. The periodic review will also examine background information, along with any associated worksheets or reference documents, to guide a comprehensive review that results in a recommendation that the Reliability Standard should be: (1) reaffirmed as is (i.e., no changes needed); (2) revised (which may include revising or retiring one or more requirements); or (3) withdrawn/retired.


Project 2017-05 Periodic Review Team of NUC-001-3

Action Appoint members, chair, and vice chair to the periodic review team (PRT) for Project 2017-05 NUC-001-3 Periodic Review, as recommended by NERC staff. Background On May 10, 2017, NERC solicited nominations for volunteers to serve on the PRT for Project 2017-05 NUC-001-3 Periodic Review. The PRT will review the Reliability Standard NUC-001-3 – Nuclear Plant Interface Coordination in accordance with the periodic review template and ultimately make a recommendation to the Standards Committee on whether the standard should be revised, retired, or re-affirmed. If the PRT recommends a revision to, or a retirement of, the Reliability Standard, it must also submit a Standard Authorization Request outlining the proposed scope and technical justification for the revision or retirement. If the periodic review results in a drafting effort, a separate drafting team will be tasked with that project. NERC staff received eight nominations from industry professionals and recommends six individuals with the requisite background, experience, skills, and temperament necessary for membership on the PRT.


Project 2017-07 Standards Alignment with Registration

Action Authorize posting the Standards Alignment with Registration Standard Authorization Request (SAR) for a 30-day formal comment period, posting the MOD-032-1 SAR for a 30-day formal comment period, and posting for nominations of a SAR drafting team to consider both and develop a combined final SAR. Background On March 19, 2015, the Federal Energy Regulatory Commission (FERC) approved the North American Electric Reliability Corporation (NERC) Risk-Based Registration (RBR) Initiative in Docket No. RR15-4-000.1 FERC approved the removal of two functional categories, Purchasing-Selling Entity (PSE) and Interchange Authority (IA), from the NERC Compliance Registry due to the commercial nature of these categories posing little or no risk to the reliability of the bulk power system.

FERC also approved the creation of a new registration category, Underfrequency Load Shedding (UFLS)-only Distribution Provider (DP), for PRC-005 and its progeny standards. FERC subsequently approved on compliance filing the removal of Load-Serving Entities (LSEs) from the NERC registry criteria.2

Several projects have addressed standards impacted by the RBR initiative since FERC approval, such as Project 2015-08 Emergency Operations revisions to standards and periodic reviews; however, there remain some Reliability Standards that require minor revisions so that they align with the post-RBR registration impacts. This project is focused on making those tailored Reliability Standards updates necessary to reflect the retirement of PSEs, IAs, and LSEs (as well as all of their applicable references). This alignment includes three categories:

1. Modifications to existing standards where the removal of the retired function may need replacement by another function. Specifically, Reliability Standard MOD-032-1 specifies certain data from LSEs that may need to be provided by other functional entities going forward. A SAR has been submitted to modify the MOD standards, and it would be posted with the Alignment with Registration SAR.

2. Modifications where the applicable entity and references may be removed. These updates may be able to follow a similar process to the Paragraph 81 initiatives where standards are redlined and posted for industry comment and ballot. A majority of the edits would simply remove deregistered functional entities and their applicable requirements/references. The impacted standards include the BAL, CIP, IRO, and TOP

1 See Order on Electric Reliability Organization Risk Based Registration Initiative, 150 FERC ¶ 61,213 (2015), available at https://www.ferc.gov/whats-new/comm-meet/2015/031915/E-3.pdf. 2 See Order on Compliance Filing, 153 FERC ¶ 61,024 (2015), available at http://www.nerc.com/FilingsOrders/us/FERCOrdersRules/Order_RBR_ROP_10152015_RR15-4.pdf.

https://www.ferc.gov/whats-new/comm-meet/2015/031915/E-3.pdf

family of standards. Additionally PRC-005 will be updated to replace distribution providers with the more-limited UFLS-only DP to align with the post-RBR registration impacts.

3. Initiatives that can address RBR updates through the periodic review process. This would include the INT-004 and NUC-001 standards. In other words, rather than making the revisions immediately, this information would be provided to the periodic review teams currently reviewing INT-004 and NUC-001 so that any changes resulting from those periodic reviews, if any, may be proposed at the same time after completion of each periodic review.

1

Standard Authorization Request (SAR) Form The North American Electric Reliability Corporation (NERC) welcomes suggestions to improve the reliability of the bulk power system through improved Reliability Standards.

Requested information

SAR Title: Standards Alignment with Registration Date Submitted: SAR Requester Name: NERC Standards Staff Organization: NERC Telephone: Email: SAR Type (Check as many as apply)

New Standard Revision to Existing Standard Add, Modify or Retire a Glossary Term Withdraw/retire an Existing Standard

Imminent Action/ Confidential Issue (SPM Section 10)

Variance development or revision Other (Please specify)

Justification for this proposed standard development project (Check all that apply to help NERC prioritize development)

Regulatory Initiation Emerging Risk (Reliability Issues Steering

Committee) Identified Reliability Standard Development Plan

NERC Standing Committee Identified Enhanced Periodic Review Initiated Industry Stakeholder Identified

Industry Need (What Bulk Electric System (BES) reliability benefit does the proposed project provide?): This project will align the standards that are impacted by the Risk-Based Registration (RBR) initiative. Purpose or Goal (How does this proposed project provide the reliability-related benefit described above?): This project aligns Standards with the FERC-approved RBR initiative. Project Scope (Define the parameters of the proposed project): This project will review and align standards impacted by the RBR initiative. Detailed Description (Describe the proposed deliverable(s) with sufficient detail for a drafting team to execute the project. If you propose a new or substantially revised Reliability Standard or definition, provide: (1) a technical justification1which includes a discussion of the reliability-related benefits of developing a new or revised Reliability Standard or definition, and (2) a technical foundation document (e.g. research paper) to guide development of the Standard or definition): This project will formally address any remaining edits to the standards that are needed to align the existing standards with the RBR initiatives. The edits include updates to the BAL, CIP, FAC, INT, IRO, MOD, NUC, and TOP family of standards to remove the references to Purchasing-Selling Entities (PSEs) and Interchange Authorities (IAs); references to the Load-Serving Entity (LSEs) will be replaced by either the Distribution Provider (DP) or the Balancing Authority (BA). Additionally, PRC-005 will replace the distribution provider with the Underfrequency Load Shedding (UFLS)-only DPs.

1 The NERC Rules of Procedure require a technical justification for new or substantially revised Reliability Standards. Please attach pertinent information to this form before submittal to NERC.

Complete and please email this form, with attachment(s) to: [email protected]


mailto:[email protected]

2

Requested information The clean-up effort of the standards can be categorized into the following:

1. Modifications to existing standards where the removal of the retired function may need replacement by another function. Specifically, Reliability Standard MOD-032-1 specifies certain data from LSEs that may need to be provided by other functional entities going forward. A SAR has been submitted to modify the MOD standards, and it would be posted with the Alignment with Registration SAR.

2. Modifications where the applicable entity and references may be removed. These updates may be able to follow a similar process to the Paragraph 81 initiatives where standards are redlined and posted for industry comment and ballot. A majority of the edits would simply remove deregistered functional entities and their applicable requirements/references. The impacted standards include the BAL, CIP, IRO, and TOP family of standards. Additionally PRC-005 will be updated to replace distribution providers with the more-limited UFLS-only DP to align with the post-RBR registration impacts.

3. Initiatives that can address RBR updates through the periodic review process. This would include the INT-004 and NUC-001 standards. In other words, rather than making the revisions immediately, this information would be provided to the periodic review teams currently reviewing INT-004 and NUC-001 so that any changes resulting from those periodic reviews, if any, may be proposed at the same time after completion of each periodic review.

Cost Impact Assessment, if known (Provide a paragraph describing the potential cost impacts associated with the proposed project): No additional costs outside of the time and resources needed to serve on the SAR and SC team. Please describe any unique characteristics of the BES facilities that may be impacted by this proposed standard development project (e.g. Dispersed Generation Resources): NA To assist the NERC Standards Committee in appointing a drafting team with the appropriate members, please indicate to which Functional Entities the proposed standard(s) should apply (e.g. Transmission Operator, Reliability Coordinator, etc. See the most recent version of the NERC Functional Model for definitions): Since LSE is being replaced by either a Distribution Provider or Balancing Authority for the standards that need to be updated, those entities will like be best suited for the MOD and PRC updates. Do you know of any consensus building activities2 in connection with this SAR? If so, please provide any recommendations or findings resulting from the consensus building activity. NA Are there any related standards or SARs that should be assessed for impact as a result of this proposed project? If so which standard(s) or project number(s)? A separate SAR on the MOD standards was recently received that would be addressed by this project. Are there alternatives (e.g. guidelines, white paper, alerts, etc.) that have been considered or could meet the objectives? If so, please list the alternatives.

2 Consensus building activities are occasionally conducted by NERC and/or project review teams. They typically are conducted to obtain industry inputs prior to proposing any standard development project to revise, or develop a standard or definition.

3

Reliability Principles Does this proposed standard development project support at least one of the following Reliability Principles (Reliability Interface Principles)? Please check all those that apply.

1. Interconnected bulk power systems shall be planned and operated in a coordinated manner to perform reliably under normal and abnormal conditions as defined in the NERC Standards.

2. The frequency and voltage of interconnected bulk power systems shall be controlled within defined limits through the balancing of real and reactive power supply and demand.

3. Information necessary for the planning and operation of interconnected bulk power systems

shall be made available to those entities responsible for planning and operating the systems reliably.

4. Plans for emergency operation and system restoration of interconnected bulk power systems shall be developed, coordinated, maintained and implemented.

5. Facilities for communication, monitoring and control shall be provided, used and maintained for the reliability of interconnected bulk power systems.

6. Personnel responsible for planning and operating interconnected bulk power systems shall be trained, qualified, and have the responsibility and authority to implement actions.

7. The security of the interconnected bulk power systems shall be assessed, monitored and maintained on a wide area basis.

8. Bulk power systems shall be protected from malicious physical or cyber attacks.

Market Interface Principles Does the proposed standard development project comply with all of the following Market Interface Principles?

Enter (yes/no)

1. A reliability standard shall not give any market participant an unfair competitive advantage. Yes

2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes

3. A reliability standard shall not preclude market solutions to achieving compliance with that standard. Yes

4. A reliability standard shall not require the public disclosure of commercially sensitive information. All market participants shall have equal opportunity to access commercially non-sensitive information that is required for compliance with reliability standards.

Yes

Identified Existing or Potential Regional or Interconnection Variances Region(s)/

Interconnection Explanation

e.g. NPCC

http://www.nerc.com/pa/Stand/Standards/ReliabilityandMarketInterfacePrinciples.pdf

http://www.nerc.com/pa/Stand/Resources/Documents/Market_Principles.pdf

4

For Use by NERC Only

SAR Status Tracking (Check off as appropriate)

Draft SAR reviewed by NERC Staff Draft SAR presented to SC for acceptance DRAFT SAR approved for posting by the SC

Final SAR endorsed by the SC SAR assigned a Standards Project by NERC SAR denied or proposed as Guidance

document Version History Version Date Owner Change Tracking

1 June 3, 2013 Revised

1 August 29, 2014 Standards Information Staff Updated template

2 January X, 2017 Standards Information Staff Revised

1

Standard Authorization Request (SAR) Form The North American Electric Reliability Corporation (NERC) welcomes suggestions to improve the reliability of the bulk power system through improved Reliability Standards.

Requested information

SAR Title: MOD-032-1 Entity Change Due to Rules of Procedure Modification Date Submitted: 06/15/2017 SAR Requester Name: Rich Hydzik on behalf of NERC Essential Reliability Resources Work Group Organization: NERC ERSWG / Avista Telephone: 509 495 4005 Email: [email protected] SAR Type (Check as many as apply)

New Standard Revision to Existing Standard Add, Modify or Retire a Glossary Term Withdraw/retire an Existing Standard

Imminent Action/ Confidential Issue (SPM Section 10)

Variance development or revision Other (Please specify)

Justification for this proposed standard development project (Check all that apply to help NERC prioritize development)

Regulatory Initiation Emerging Risk (Reliability Issues Steering

Committee) Identified Reliability Standard Development Plan

NERC Standing Committee Identified Enhanced Periodic Review Initiated Industry Stakeholder Identified

Industry Need (What Bulk Electric System (BES) reliability benefit does the proposed project provide?): This project is intended to facilitate accurate data collection to facilitate modeling of the Distribution Provider’s (DP) facilities. Purpose or Goal (How does this proposed project provide the reliability-related benefit described above?): Accurate modeling of distribution facilities is required to ensure that power system models accurately reflect the bulk power system (BPS) performance. These models are used in system analysis for planning purposes and construction of a reliable BPS. These models are in used in system analysis for operating purposes to ensure a reliable BPS in both short term, day-ahead, and real-time operational planning analyses. Project Scope (Define the parameters of the proposed project): This project proposes removing the Load Serving Entity (LSE) from the Applicability Section (4.1.3) and replacing LSE with Distribution Provider (DP) as the applicable entity for Section 4.1.3. LSE is no longer considered a reliability entity due to a change in the NERC Rules of Procedure. The DP is defined as “provides and operates the ‘wires’ between the transmission system and the end use customer.” The DP is the applicable entity to provide data for power system modeling and analysis for distribution systems. Attachment 1 should be modified by replacing the applicable entity LSE with DP.

Complete and please email this form, with attachment(s) to: [email protected]



2

Requested information Detailed Description (Describe the proposed deliverable(s) with sufficient detail for a drafting team to execute the project. If you propose a new or substantially revised Reliability Standard or definition, provide: (1) a technical justification1which includes a discussion of the reliability-related benefits of developing a new or revised Reliability Standard or definition, and (2) a technical foundation document (e.g. research paper) to guide development of the Standard or definition): This project proposes removing the Load Serving Entity (LSE) from the Applicability Section (4.1.3) and replacing LSE with Distribution Provider (DP) as the applicable entity for Section 4.1.3. LSE is no longer considered a reliability entity due to a change in the NERC Rules of Procedure. The DP is defined as “provides and operates the ‘wires’ between the transmission system and the end use customer.” The DP is the applicable entity to provide data for power system modeling and analysis for distribution systems. Cost Impact Assessment, if known (Provide a paragraph describing the potential cost impacts associated with the proposed project): Cost impacts should be minimal. Planning Coordinator and Transmission Planners are required to collect modeling data under MOD-032-1. In the past, Planning Coordinator and Transmission Planners collected from LSE’s. This entity would be the DP under the proposed change. Please describe any unique characteristics of the BES facilities that may be impacted by this proposed standard development project (e.g. Dispersed Generation Resources): None To assist the NERC Standards Committee in appointing a drafting team with the appropriate members, please indicate to which Functional Entities the proposed standard(s) should apply (e.g. Transmission Operator, Reliability Coordinator, etc. See the most recent version of the NERC Functional Model for definitions): Planning Coordinator Transmission Planner Transmission Operator Distribution Provider Do you know of any consensus building activities2 in connection with this SAR? If so, please provide any recommendations or findings resulting from the consensus building activity. No Are there any related standards or SARs that should be assessed for impact as a result of this proposed project? If so which standard(s) or project number(s)? No Are there alternatives (e.g. guidelines, white paper, alerts, etc.) that have been considered or could meet the objectives? If so, please list the alternatives. None identified

Reliability Principles Does this proposed standard development project support at least one of the following Reliability Principles (Reliability Interface Principles)? Please check all those that apply.


1 The NERC Rules of Procedure require a technical justification for new or substantially revised Reliability Standards. Please attach pertinent information to this form before submittal to NERC. 2 Consensus building activities are occasionally conducted by NERC and/or project review teams. They typically are conducted to obtain industry inputs prior to proposing any standard development project to revise, or develop a standard or definition.

http://www.nerc.com/pa/Stand/Standards/ReliabilityandMarketInterfacePrinciples.pdf

3

Reliability Principles









Market Interface Principles Does the proposed standard development project comply with all of the following Market Interface Principles?

Enter (yes/no)

1. A reliability standard shall not give any market participant an unfair competitive advantage. yes

2. A reliability standard shall neither mandate nor prohibit any specific market structure. yes

3. A reliability standard shall not preclude market solutions to achieving compliance with that standard. yes


yes

Identified Existing or Potential Regional or Interconnection Variances Region(s)/

Interconnection Explanation

e.g. NPCC

http://www.nerc.com/pa/Stand/Resources/Documents/Market_Principles.pdf

4

For Use by NERC Only

SAR Status Tracking (Check off as appropriate)

Draft SAR reviewed by NERC Staff Draft SAR presented to SC for acceptance DRAFT SAR approved for posting by the SC

Final SAR endorsed by the SC SAR assigned a Standards Project by NERC SAR denied or proposed as Guidance

document Version History Version Date Owner Change Tracking



2 January X, 2017 Standards Information Staff Revised


Standard Authorization Request for BAL-003-1.1

Action Authorize posting the BAL-003-1.1 Standard Authorization Request (SAR) submitted by the Northwest Power Pool Frequency (NWPP) Response Sharing Group (FRSG), and assign the SAR to the Project 2017-01 (Modifications to BAL-003-1.1) SAR Drafting Team nominated under the pending Operating Committee Resource Subcommittee (RS) SAR on BAL-003-1.1, with a goal of developing one combined SAR for further review by the Standards Committee (SC). Background NERC received a SAR from the NWPP FRSG, which is comprised of 18 Balancing Authorities. The SAR proposes modifications to BAL-003-1.1 and its supporting documentation. The SAR seeks to revise the Interconnection Frequency Response Obligation (IFRO) calculation in BAL-003-1.1 consistent with matters identified in the 2016 Frequency Response Annual Analysis Report (FRAA).1 This SAR recommends changes similar to the RS SAR that the SC authorized for posting in June 2017,2 and which has been named Project 2017-01.

This NWPP FRSG SAR also seeks to make additional changes in a second phase of the project that would substantially modify the existing standard and its applicability. The NWPP FRSG has provided the attached technical justification document in support of its proposed substantial revisions to the standard.3

Please see the Purpose and Goal of the attached SAR for NWPP FRSG’s proposed two-phase project, that would (i) address issues similar to those discussed in the FRAA and RS SAR during Phase I of the project; and (ii) address substantial revisions to the scope and applicability of the standard during Phase II of the project.

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). 2 See June Standards Committee Agenda Item 7, available at http://www.nerc.com/comm/SC/Agenda%20Highlights%20and%20Minutes/SC%20Agenda%20Package_June142017.pdf. 3 See Standard Processes Manual at p. 16 (stating “[e]ach SAR that proposes a ‘new’ or substantially revised Reliability Standard or definition should be accompanied by a technical justification that includes, as a minimum, a discussion of the reliability-related benefits and costs of developing the new Reliability Standard or definition, and a technical foundation document (e.g., research paper) to guide the development of the Reliability Standard or definition. The technical document should address the engineering, planning and operational basis for the proposed Reliability Standard or definition, as well as any alternative approaches considered during SAR development”).

http://www.nerc.com/comm/OC/Documents/2016_FRAA_Report_2016-09-30.pdf

http://www.nerc.com/comm/SC/Agenda%20Highlights%20and%20Minutes/SC%20Agenda%20Package_June142017.pdf

Standard Authorization Request Form

NERC welcomes suggestions to improve the reliability of the bulk power system through improved Reliability Standards. Please use this form to submit your request to propose a new or a revision to a NERC Reliability Standard.

Request to propose a new or a revision to a Reliability Standard

Title of Proposed Standard: BAL-003-1 – Frequency Response and Frequency Bias Setting

Date Submitted: 2/17/2017

SAR Requester Information

Name: Jerry Rust – Designated Representative For Frequency Response Sharing Group (18 BAs)

Organization: [NWPP] Frequency Response Sharing Group

Telephone: 503.445.1074 Email: [email protected]

SAR Type (Check as many as applicable)

New Standard

Revision to Existing Standard

Withdrawal of Existing Standard

Urgent Action

SAR Information

Industry Need (What is the industry problem this request is trying to solve?):

There are several problems with respect to the existing Standard: • The IFRO calculation in BAL-003-1 needs to be revised due to inconsistencies identified in the

2016 Frequency Response Annual Analysis (FRAA) such as the IFRO values with respect to Point C and varying Value B, the Eastern Interconnection Resource Contingency Protection Criteria, evaluation of t0 and clarification of language in the 2016 Frequency Response Annual Analysis (FRAA) Report.

When completed, please email this form to:

[email protected]




Standard Authorization Request Form 2

SAR Information

• The IFRO calculation in BAL-003-1 is retrospect and has no bearing on real-time reliability • Allocation of the IFRO to the BAs has no reflection of real-time situation; it is predicated on two-

year old information. • The applicability to the FRSG or a BA that is not part of an FRSG is not tied to any ability to

provide response, since response is either from generator or load. The BA is responsible for balancing, frequency load response is inherent to load characteristics and non controllable unless load is shed. Generator response is controllable through proper governor operation thus there is direct applicability to Generator Owners and Operators.

• The arbitrary allocation formula assumes all BAs have exactly the same characteristics, such as load response, mix and type of generation, and others, which is not true, and thus is not providing comparability across all BAs.

• FRM is calculated using net interchange actual which assumes all BAs have exactly the same settings for response, where one large BA could have a governor and or speed controller setting with zero deadband and set to respond at twice their allocated requirement, that may result in the apparent suppressing of the adjacent BA’s response, since measurement is interchange. In addition, BAL-003-1 appears to drive an arbitrary market and pricing, thus it is not market neutral.

• The FRM measurement period (20-52 seconds) is too far beyond the event to accurately measure the frequency-response provided (10-20 seconds) to arrest the frequency deviation. FRM should be measured correctly and obligated to all the correct responsible parties within an Interconnection.

• The intent of the Standard is to assure adequate Frequency Response for the Interconnection. The standard should address the adequate amount of Frequency Response to arrest sudden frequency deviations within an Interconnection. The standard must be able to measure all types of Frequency Response and credit the providers. The current standards does not reflect different types of Frequency Response and the timing of such response.

Purpose or Goal (How does this request propose to address the problem described above?):

Revise the BAL-003-1 standard in a two phase approach

First phase address:

• the inconsistencies in calculation of IFROs for Interconnection Frequency Response performance changes of Point C and/or Value B;

• the Eastern Interconnection Resource Contingency Protection Criteria; • the evaluation of t0; and,


SAR Information

• 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. Please refer to the 2016 FRAA Report for additional information.

Second phase address:

• Assign the ability to control and provide Frequency Response to the correct applicable entity; • Tie Frequency Response to real-time reliability; • Eliminate arbitrary and non-comparable formulas; • Establish a process to measure Frequency Response that is not an arbitrary estimate using

NetActual Interchange; • Establish a process that reflects measurement of real-time reliability associate with frequency

response; • Reflect real-time topology of BES and capability and variances in types of response; • Eliminate the incorrect signals to the market for arbitrary pricing and conditions; and • Develop a more correct real-time reliability standard.

Identify the Objectives of the proposed standard’s requirements (What specific reliability deliverables are required to achieve the goal?):

For Phase 1, please refer to the 2016 Frequency Response Annual Analysis (FRAA) Report.

For Phase 2, modify the standard reflecting real-time with the correct responsible entity identified.

Brief Description (Provide a paragraph that describes the scope of this standard action.)

For Phase 1, during the 2016 annual evaluation of the values used in the calculation of the IFRO, the above mentioned problems were identified. The scope of the work will be to (1) address the inconsistency in the CBR ratio, (2) reevaluate the Resource Contingency Protection Criteria for each interconnection, (3) reevaluate the frequency nadir point limitations (currently limited to t0 to t+12), and clarify language in the 2016 Frequency Response Annual Analysis (FRAA) Report. Please refer to the 2016 FRAA Report for additional information.

For Phase 2, the FRSG has identified the above issues and the unintended consequences, without addressing real-time reliability. The scope of the work will be to (1) establish a real-time reliability standard addressing the necessary frequency response to maintain reliability, (2) establish


SAR Information

comparability for the correct responsible entity, (3) develop real-time measurements incorporating topology difference, and (4) eliminate the incorrect indicators.

Detailed Description (Provide a description of the proposed project with sufficient details for the standard drafting team to execute the SAR. Also provide a justification for the development or revision of the standard, including an assessment of the reliability and market interface impacts of implementing or not implementing the standard action.)

For Phase 1: • Consider revising the BAL-003-1 standard concerning #1 above through the standards

development process to correct the inconsistency in the CBR ratio. The CBR ratio in the IFRO calculation couples Point C and Value B together, resulting in IFRO trends that do not align with the intent of the standard. Improvement in Value B with no change in Point C (improving recovery phase) would result in higher obligation to be carried, essentially penalizing improved performance.

• Consider revising the BAL-003-1 standard concerning #2 above through the standards development process to modify the Resource Contingency Protection Criteria. The Resource Contingency Protection Criteria for each interconnection should be revised to help ensure sufficient primary frequency response is maintained. The Eastern Interconnection uses the “largest resource event in last 10 years”, which is the 4 August 2007 event. The standard drafting team should revisit this issue for modifications to BAL-003-1 standard, and the Resources Subcommittee should recommend how the events are selected for each interconnection.

• Consider revising the BAL-003-1 standard concerning #3 above through the standards development process to revisit the frequency nadir point used in the calculation. Many events, particularly in the Eastern Interconnection due to its large synchronous inertia, tend to have a frequency nadir point that exceeds the t0 +12 seconds specified in BAL-003-1. Therefore, some events are characterized with a Point C value that is only partially down the arresting period of the event and does not accurately reflect the actual nadir. BAL-003-1 should be modified to allow for accurate representation of the Point C nadir value if exceeding t0+12 seconds. The actual event nadir can occur at any time, including beyond the time period used for calculating Value B (t0+20 through t0+52 seconds), and may be the value known as Point C’ which typically occurs from 72 to 95 seconds after t0.

• Consider revising BAL-003-1 Attachment A to provide clarity to the intent with particular attention to FRSGs and the timeline for Balancing Authority Frequency Response and Frequency Bias Setting.

Please refer to the 2016 FRAA Report for additional information. For Phase 2:


SAR Information

• Consider revising BAL-003-1 standard to reflect real-time measurement of frequency performance vs. a two year old allocation.

• Consider revising BAL-003-1 Standard to reflect the correct applicable entity that controls and provides frequency response.

• Consider revising BAL-003-1 Standard to reflect comparability among the applicable entities. • Consider revising BAL-003-1 Standard to eliminate arbitrary allocation of responsibility. • Consider revising BAL-003-1 Standard to eliminate the incorrect signals that have created

unintended consequences.

Reliability Functions

The Standard will Apply to the Following Functions (Check each one that applies.)

Reliability Coordinator Responsible for the real-time operating reliability of its Reliability Coordinator Area in coordination with its neighboring Reliability Coordinator’s wide area view.

Balancing Authority Integrates resource plans ahead of time, and maintains load-interchange-resource balance within a Balancing Authority Area and supports Interconnection frequency in real time.

Interchange Authority Ensures communication of interchange transactions for reliability evaluation purposes and coordinates implementation of valid and balanced interchange schedules between Balancing Authority Areas.

Planning Coordinator Assesses the longer-term reliability of its Planning Coordinator Area.

Resource Planner Develops a one year plan for the resource adequacy of its specific loads within a Planning Coordinator area.

Transmission Planner Develops a one year plan for the reliability of the interconnected Bulk Electric System within its portion of the Planning Coordinator area.

Transmission Service Provider

Administers the transmission tariff and provides transmission services under applicable transmission service agreements (e.g., the pro forma tariff).

Transmission Owner Owns and maintains transmission facilities.



Transmission Operator

Ensures the real-time operating reliability of the transmission assets within a Transmission Operator Area.

Distribution Provider Delivers electrical energy to the end-use customer.

Generator Owner Owns and maintains generation facilities.

Generator Operator Operates generation unit(s) to provide real and reactive power.

Purchasing-Selling Entity

Purchases or sells energy, capacity, and necessary reliability-related services as required.

Market Operator Interface point for reliability functions with commercial functions.

Load-Serving Entity Secures energy and transmission service (and reliability-related services) to serve the end-use customer.

Reliability and Market Interface Principles

Applicable Reliability Principles (Check all that apply).












Does the proposed Standard comply with all of the following Market Interface Principles?

Enter

(yes/no)

1. A reliability standard shall not give any market participant an unfair competitive advantage.

Yes

2. A reliability standard shall neither mandate nor prohibit any specific market structure.

Yes

3. A reliability standard shall not preclude market solutions to achieving compliance with that standard.

Yes


Yes

Related Standards

Standard No. Explanation

None

Related SARs

SAR ID Explanation

None


Related SARs

Regional Variances

Region Explanation

ERCOT None.

FRCC None.

MRO None.

NPCC None.

RFC None.

SERC None.

SPP None.

WECC None.

Version History

Version Date Owner Change Tracking 1 June 3, 2013 Revised


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Standard Authorization Request Revision to BAL-003-1.1 Frequency Response and Frequency Bias Setting

June 28, 2017

The North American Electric Reliability Corporation (NERC) Standard Process Manual Version 3, Section 4.0, Process for Developing, Modifying, Withdrawing or Retiring a Reliability Standard requires a Standard Authorization Request (SAR) that proposes to substantially revise a Reliability Standard to be accompanied by a technical justification that includes, at a minimum, a discussion of the reliability-related benefits and costs of modifying the Reliability Standard and a technical foundation document to guide the development of the Reliability Standard. North America’s only registered Frequency Response Sharing Group (FRSG), consisting of 18 Balancing Authority Areas (BAAs) within the Western Interconnection (encompassing 38 BAAs in total), submitted a SAR on February 17, 2017 requesting a revision to the existing Reliability Standard BAL-003-1.1 (BAL-003). NERC has requested additional technical justification for the SAR per the Standard Process Manual. The material in this attachment was prepared by the [NWPP] FRSG.

This document provides further technical justification for the previously submitted SAR, organized according to the following topics:

• Real-Time Reliability

• Event Selection

• Measurement

• Assumption behind the current standard

• Goal of a Reliability Standard

Real-Time Reliability

BAL-003 states that compliance is judged according to performance for the median event out of a larger set of historical events evaluated for a particular compliance year. This suggests it is acceptable for BAAs to provide adequate frequency response just over half the time. The standard assumes a statistical probability that if one BAA fails there will be enough excess response from other BAAs to compensate. But it also follows that all BAAs could simultaneously provide insufficient frequency response on multiple occasions without any compliance failures. This fact alone indicates BAL-003 does not adequately assure real-time reliability.

Furthermore, relying on historical event analysis to establish and evaluate frequency response does not ensure frequency response is available in real-time. Frequency response is needed 24 hours a day, 365 day a year, to manage interconnection frequency and recover from frequency events. If the Interconnection were dispatched as a single system, the operator would estimate frequency response capability needed from each resource and dispatch those resources as

Agenda Item 12(ii)Standards CommitteeJuly 19, 2017

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necessary to ensure reliability. An interconnection made up of multiple BAAs should not be treated any differently.

BAA operators must decide how to operate their systems to support reliability. BAL-003, in its current form, does not specify the amount of frequency response reserves needed in real-time for reliability—that is, capacity needed on frequency responsive resources to be prepared for the design event of an Interconnection Most Severe Single Contingency. Yet NERC’s Reliability Guideline for Operating Reserve Management (Guideline) addresses this question directly. Section V.a. of the guideline states:

To determine an initial target (at scheduled frequency) frequency responsive reserve level (in MW) for a given responsible entity, simply multiply 10 times the responsible entity’s FRO (because FRO is in MW/0.1 Hz) by the MDF for the responsible entity’s Interconnection. An example to illustrate this:

Given: ABC responsible entity is in the Eastern Interconnection (EI) and its pro-rata portion of IFRO is 1.5%.

The key EI parameters from Table 1 are: IFRO = 1002 MW/0.1 Hz and MDF = 0.449 Hz.

The responsible entity’s FRO is 1.5% *1002 MW/0.1 Hz or 15.2 MW/0.1 Hz.

The responsible entity’s initial frequency responsive reserve target is 10 * 15.2 * 0.449 or 67.48 MW.

The initial target may need to be modified based on several factors, most of which are addressed later in this section. For example, if actual performance indicates additional response is needed, then the target should be increased.

The studies performed by NERC determined the Maximum Delta Frequency A to B based on a statistical analysis of the B to C ratio. This study, in conjunction with the Guideline, indicates the Western Interconnection should maintain frequency responsive reserve capacity online at all times equal to approximately three times the Interconnection Frequency Response Obligation (IFRO). This amount is disputable and seems like an overestimate of reserve needed in the Western Interconnection. This is in light of The Western Interconnection’s frequency response performance in recent events approximately the MW size of the double Palo-Verde design event. An overestimate or not, the current standard only obligates a BA to keep some level of this reserve available a little more than half of the year. BAL-003 must provide for this and more study needs to justify the reserves needed by BAs in real-time. Until then, the guideline provides some guidance for how much a BAA should hold in MW capacity, but the Guideline further states:

The responsible entity also may choose to perform a risk analysis in determining the level of frequency responsive reserve that assures compliance at an acceptable cost.

This presents a problem. Reliability should not turn on economic decisions. Reliability requirements must be incorporated into standards and not just captured in guidelines that are

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enforced solely by peer pressure within industry. Instead of being clear, BAL-003 sends mixed messages to BAAs.

Given the current gap in BAL-003 and the “wiggle room” in the Guideline, BAAs could achieve compliance in many unreliable ways. For example, a BAA could only hold enough capacity to cover a 0.1 Hz deviation, because most BAL-003 measurement events in the Western Interconnection are less than 0.1 Hz (since evaluation of FRM as currently prescribed in BAL-003-1.1 began in compliance year 2015, the average frequency deviation of all NERC selected events was only -0.060 Hz/0.10 MW). Or, a BAA could plan to meet all events in two quarters of a compliance year, and then neglect the other two quarters. A pattern that could be desirable for entities that take down generation for annual maintenance, normally in the spring in the Western Interconnection. Even if BAAs operate conscientiously to protect reliability, BAL-003 creates confusion about what is needed in real-time to support reliability.

Following FERC’s order approving BAL-003, markets have developed for “paper” transactions in which one BAA can agree with another to transfer “credit” for calculated frequency response (referred to as Frequency Response Transfers). While the members of FRSG generally support allowing BAAs to comply through Frequency Response Transfers, they worry that assessing compliance according to a median-based metric could degrade real-time reliability.

For example:

Suppose a BAA cannot fully comply with BAL-003, but has existing generation equipment that does provide some frequency response. The BAA finds itself integrating substantial variable generation that does not provide automatic frequency response. The increasing variable generation displaces frequency-responsive generating units for at least half of the operating hours. The BAA weighs its options. It could pay generators to improve equipment; it could alter dispatch to increase headroom on frequency responsive units; it could install a battery capable of frequency response; and so on. After analysis, the BAA decides it is most economic to meet its Frequency Response Obligation (FRO) entirely through Frequency Response Transfers. The BAA does not seek to improve equipment capability, and it has every right to shut down frequency-responsive units to make room for the new variable generation. Available frequency response will decline compared to historic levels. The BAA now relies entirely on the transferring BAA. In this scenario, historic frequency response is lost. The transferring BAA need only respond adequately for more than half of the compliance measurement events, and the purchasing BAA is relieved of any obligation to provide frequency response in real-time. This also flies in the face of the underlying assumption of statistical probability.

BAL-003 does not require operational (as opposed to paper) transfers of frequency response, and therefore has not resulted in creation of real-time markets for frequency response. NERC regulations should drive market signals that reflect what is truly needed for reliability, and ensure 100% coverage through equipment, capacity, and dispatch.

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Another problem with BAL-003 is that it measures the average frequency support in the 20 to 52 seconds following a frequency event, even though machine action is needed within the first 20 seconds to arrest rapid frequency decline in the Western Interconnection. The measurement lag encourages BAAs to delay response to improve compliance metrics, which subverts the primary purpose of the standard. Western Interconnection frequency could drop low enough to trigger Underfrequency Load Shedding without a single BAA failing to comply with BAL-003. This lessens, rather than enhances, Western Interconnection reliability.

The FRSG recognizes, as do NERC and FERC, that the generation fleet is changing. Frequency response will likely decline unless operators maintain frequency-responsive capability and resources are dispatched in real-time to provide adequate headroom for frequency response. The FRSG also concurs with NERC that, historically, the Western Interconnection has had sufficient frequency response. To speak plainly, the sky is not falling and risks to reliability may not be immediate. But neither NERC nor the electric utility industry should ignore this issue. Operational requirements must be clearly stated to ensure that equipment, operations, and markets develop to support real-time reliability now and in the future.

Event Selection and Measurement:

Several aspects of BAL-003’s event selection and response measurement process may perversely reward poor performance and penalize proper performance. NERC’s Reliability Guideline on Primary Frequency Control encourages Generator Operators to set governor dead bands of no more than 36 mHz (and recommends using an even smaller dead band), with a ramped (not stepped) drop of between 4% to 5%. While a smaller dead band may be feasible in the Eastern Interconnection, frequency within the smaller Western Interconnection is more variable. Here, smaller dead bands would impose undue burdens on thermal generators. Likewise, due to the size of the Western Interconnection, credible N-1 events can drop the C and B frequency points well outside the 36 mHz dead band.

In the Western Interconnection, the generation fleet provides primary frequency response for large events through governor action. Operators have gone to significant effort, in good faith, to tune governors and associated controls according to the Guideline to protect reliability and comply with BAL-003. Yet the current methods of event selection and response measurement do not take these settings into account.

One deficiency is that FRO and Frequency Response Measured (FRM) derive from change in frequency instead of actual frequency. Many governors have been set (as indicated by the Guideline) to use a dead band of 36 mHz. Therefore any changes in frequency between 59.965 and 60.035 Hertz should not trigger frequency response, but these governors with governor droop set correctly, should respond to frequencies outside the dead band. Likewise, because the governor response is ramped starting at the edge of the dead band instead of stepped, the response for a frequency that is outside but close to the dead band should be small. Therefore a change in frequency from 60.03 to 59.97 should not result in governor response, a change from 60.00 to 59.94 should result in moderate governor response, and a change from 59.97 to 59.91 should result in substantial governor response, even though all three events have the

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exact same frequency delta. Yet the FRM and FRO calculations treat these as equivalent events, penalizing BAAs for correctly respecting the NERC-defined dead band.

Another deficiency is the gap between 0 and 20 seconds in the measurement period. The first 8-12 seconds of an event are when frequency excursions are actually arrested. While this period is difficult to measure through Interchange metering, it is the critical period to prevent underfrequency load shedding. The measurement period lag (20-52 seconds) encourages BAAs to install controls with a 15 or 20 second delay in frequency response. Control equipment could operate less often without compromising compliance scores—certainly an unintended consequence, and one that could undermine the reliability of the Interconnection. This practice of delaying response to ensure compliance for the sake of economics at the expense of reliability is already being implemented on resources within the Western Interconnection as a direct result of the current BAL-003-1.1 measurement criteria.

Yet another issue with the FRM measure is its assumption that frequency response is linear. Although a linear assumption is reasonable for governor technology, even a governor can behave non-linearly. A step change response, capable in inverter based technology, drastically inflates the FRM measure within the first tenth of a Hertz. For example, a battery capable of injecting 10 MW upon sensing a frequency change would achieve a FRM of 10 MW/0.1 Hz for an A to B event of 0.1 Hz. That same battery would achieve a FRM of 100 MW/0.1 Hz for an A to B event of 10 mHz. The difference between FRM for the same MW injection within the first tenth of a Hertz is close to 90 MW/0.1 Hz while the difference one tenth and two tenths is only 5 MW/0.1 Hz. Because of the fraction on the denominator of the FRM equation, the equation becomes less variable for an A to B value of 0.1 Hz or greater. This needs to be accounted for in the BAL 003 standard.

There are additional problems with the number of events selected for compliance assessment and the median response requirement. By requiring selection of numerous events, regardless of how many significant frequency events occur, BAL-003 skews compliance evaluation toward events within the 36 mHz dead band. This penalizes proper performance as described above. Even if all frequency events within the dead band were excluded, the events selected to date (including previous year sample selections) have an average delta frequency of roughly 0.06 Hz. This means BAAs could remain compliant even if they carried only enough frequency responsive reserve to cover frequency changes of less than 0.1 Hz—far less than the Interconnection would need to prevent underfrequency load shedding in a major event (which is what BAL-003 is intended to prevent).

BAL-003 is intended to ensure the Western Interconnection has enough frequency responsive reserve to prevent underfrequency load shedding for a net loss of 2,440 MW, with a starting frequency of 59.976. As described above, a BAA that has installed generator controls to provide exactly that response using the NERC Guidelines will be penalized for not responding to small events (which is correct), whereas a BAA that carries just enough frequency responsive reserve to respond to much smaller events, or intentionally delays its response to optimize compliance over reliability, could be rewarded.

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This means the Western Interconnection could experience multiple underfrequency load shedding events in a year without a single BAA failing the standard. Conversely, multiple BAAs could fail despite providing proper and reliable frequency response. Not only is this biased against BAAs that take action in good faith to follow NERC’s Guideline, but over time, as BAAs migrate toward more cost-effective compliance methods, the Western Interconnection’s initial frequency response, as well as total frequency response available, could decline.

Use of “Net Actual Interchange” to Measure Compliance with BAL-003, R1:

Net Actual Interchange (NIA) is defined as the algebraic sum of all metered interchange over all interconnections between two physically adjacent BAAs. BAL-005-0.2b allows a scan rate of up to six seconds for both tie-line telemetry and automatic generation control (AGC) calculation. Using these values to calculate FRM has many inherent problems, and is ill suited to measure BAA response to frequency deviations caused by losses of large generating resources.

(1) The time frame for calculating a BAA’s FRM is 20 to 52 seconds after a frequency deviation is identified in historical data provided by the BAA’s energy management system (EMS). Many EMS/SCADA systems do not or cannot synchronize tie-line telemetry for calculation of Area Control Error (ACE) or FRM. Due to scan rates of telemetry equipment, this non-synchronization of tie-line data can dramatically skew the calculation of FRM. Although there is no intentional time delay in any of the telemetered data, permitted scan rates of up to six seconds can create lags of up to twelve seconds, depending on the timing of the event and the measurement transmitted to the host EMS for recording and calculation purposes. Measuring response beginning at 20 seconds after the frequency event is detected can skew a BAA’s apparent FRM performance—whether for better or for worse, at random.

(2) Although most measurements for NIA occur at physical meters on interties, many BAAs have pseudo-tie telemetry that does not originate from a physical meter. These pseudo-tie values are commonly associated with jointly owned generating facilities that may contribute significantly to a BAA’s FRM. In addition to lag effects from scan rates of remote terminal unit (RTU) data, there are several other delays in receiving, calculating, and transmitting measurements used to calculate pseudo-tie values. Once a host BAA receives the core measurements to derive a preliminary pseudo-tie value, several additional computational and transmitting cycles must occur. At a minimum, the host BAA must run a calculation within its EMS or other control system, which may take up to six seconds. Once the value has been calculated, it is transmitted to neighboring BAAs that share the pseudo-tie value, typically through Inter-Control Center Communication Protocol (ICCP) data links. The ICCP transmittal is separate from the calculation process, with up to 12 seconds of latency between sending and receiving. As with the timing lag described in Item 1 above, the skewing effects of pseudo-tie measurements and calculation, with respect to BAL-003 compliance evaluation, are essentially random.

(3) When a frequency deviation occurs due to loss of a large generator, generator governors respond automatically to the resulting drop in frequency. If a BAA is electrically between a large resource providing frequency response and the lost generation, transmission flows

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can increase on the intermediary BAA’s system. As transmission flows increase, transmission line losses increase as well. These losses appear as increased load on the intermediary BAA’s system, which can in turn affect apparent FRM performance. In some instances, even though the BAA’s generation and load response was appropriate, the losses incurred due to neighboring generator response can overwhelm the BAAs actual FRM.

(4) There is no accommodation for a BAA experiencing an intentional change to its NIA. In previous years, scheduled interchange would be adjusted only within the 10 minutes ahead of or after the operating hour or during curtailments to manage rare unplanned transmission events. Frequency bias procedures allowed BAAs to ignore events that occurred during these intentional changes to Net Scheduled Interchange. With the advent of 15-minute scheduling, schedule changes can occur during 50 out of every 60 minutes of any operating hour. Furthermore, many BAA’s representing a significant share of the WECC interconnection are currently operating in a joint 5-minute market, which results in intentional ramps at all times. This market continues to expand and other markets are developing, increasing the percentage of BAA’s that experience constant intentional ramps due to NSI changes. If, by chance, a frequency deviation (selected for compliance evaluation) were to occur during this intentional re-dispatch, chances are 50%-50% that the BAA could be benefitted or harmed for BAL-003 compliance purposes. These intentional changes in Net Scheduled Interchange do not adversely affect reliability, but could harm BAA performance under BAL-003.

(5) BAAs often adjust internal generation in anticipation of daily load variations. During certain seasons, a BAA may experience relatively large changes in native load. The BAA may intentionally dispatch generation to prepare for these anticipated changes in native load and expected changes to hourly NIA. Again, if by chance, a frequency deviation were to occur during this intentional re-dispatch, BAA compliance measurement could be improved or degraded, with no correlation to reliability.

(6) BAAs may also adjust internal generation to manage anticipated changes in output from Variable Energy Resources (VERs), primarily photovoltaic (PV) generating facilities. The California Independent System Operator (CAISO) has stated that as much as 47% if its BAA load has been served by VERs. Both increases and decreases to PV output occur on a daily basis. To manage these changes in anticipated VERs, a BAA will proactively ramp conventional generation or schedules. The result, if there is a concurrent frequency event used to measure BAL-003 compliance, is as descried above in Items 4 and 5.

Obligation for Generator Owners and Operators:

Frequency Response (FR) is a measure of an Interconnection’s ability to arrest and stabilize frequency deviations following the sudden loss of generation or load, and is affected by the collective responses of generation and load throughout the Interconnection. The primary FR provided the generation fleet within an Interconnection has a significant impact on the overall FR. BAL-003 specifies the amount of frequency response (per Hertz of frequency deviation) needed from BAAs to maintain Interconnection frequency within predefined bounds and

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includes requirements for the measurement and provision of FR. But BAL-003 contains nothing that obligates Generator Owners/Operators (GO/GOP) to provide primary frequency response. BAAs are disadvantaged under the standard, with few options beyond expensive yearly markets for frequency responsive reserve capacity products. If BAL-003 is intended to ensure a positive frequency response to frequency excursions, then GO/GOPs must be subject to the standard.

Nothing in any other NERC standard or in the provisions of the FERC Pro Forma Tariff or Generation Interconnection Agreement (GIA) requires GO/GOPs to provide primary frequency response. Even a generator following the NERC Reliability Guideline – Primary Frequency Control may, in many cases, fail to respond due to the lack of headroom during an event or the blocking of the governor signal in the plant control or auxiliary systems. The BAA has no way through GIAs or tariff language to require otherwise. BAL-003 allocates a portion of the IFRO to the individual BAA, which must then attempt to allocate the obligation to all generators in the BAA. In most cases, GO/GOPs have refused to run generator units to reserve headroom for frequency response. Some GO/GOPs have asked how much they need to provide. BAAs can only explain that BAL-003 requires response expressed as a MW/0.1 Hz range. This makes it difficult to define exactly what they must provide. The retrospective nature of this standard does not enable BAAs to determine future performance and or inform GO/GOPs of their forward-looking obligation.

The ERCOT BAL-001-TRE-1, R7, “Primary Frequency Response” standard obligates the GO/GOPs to maintain functional generators and to also provide frequency response during relevant events. “Each GO shall operate each generating unit/generating facility that is connected to the interconnected transmission system with the Governor in service and responsive to frequency when the generating unit/generating facility is online and released for dispatch, unless the GO has a valid reason for operating with the Governor not in service and the GOP has been notified that the Governor is not in service.” BAA obligations under ERCOT’s standard are mostly reporting and tracking response from all generators.

FERC recognized the ERCOT standard for primary frequency response got it right and should be a pattern for future standards and revisions to current standards.1 The ERCOT standard provides a useful model for changes needed to remedy the problems with BAL-003, or develop a Western Interconnection variance that recognizes how it differs from other regions in the NERC footprint.

NERC has pointed out that primary frequency response capability, by itself, would not require a resource to respond if called upon to help a BAA meet its FRO, and that, as a result, it is important to have mechanisms to ensure that sufficient frequency response capability is not only available but ready to respond at all times. If NERC believes there are mechanisms available to the BAAs, then the standard should define those mechanisms. It is unclear how NERC could expect a BAA to meet its FRO without generator response provided by governor signals.

1 FERC has also accepted Regional Reliability Standard BAL-001-TRE-01 (Primary Frequency Response in the ERCOT Region) as mandatory and enforceable. North American Electric Reliability Corporation, 146 FERC ¶ 61,025 (2014).

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In its Notice of Proposed Rulemaking (NOPR) on Primary Frequency Response (Docket No. RM16-6-000), FERC stated that proposed modifications to GIAs for both large and small generating facilities (both synchronous and non-synchronous) would require new generators to install, maintain, and operate equipment capable of providing primary frequency response as a condition of interconnection. FERC recognized that “[w]hile NERC Reliability Standard BAL-003-1.1 establishes requirements for balancing authorities, it does not include any requirements for individual generator owners or operators,” and that “[w]hen considered in aggregate, the primary frequency response provided by generators within an Interconnection has a significant impact on the overall frequency response.”

The NOPR also cited a 2010 NERC survey of generator owners and operators, which found that,

“. . . only approximately 30 percent of generators in the Eastern Interconnection provided primary frequency response, and that only approximately 10 percent of generators provided sustained primary frequency response. This suggests that many generators within the Interconnection disable or otherwise set their governors or outer-loop controls such that they provide little to no primary frequency response.” (Footnotes omitted)

If FERC believes that generating facilities should be capable of providing frequency response, then the NERC standard should obligate GO/GOPs to provide it. If the generators have a significant impact on the overall frequency response, why would they be excused from BAL-003 compliance?

As noted above, NERC has approved a voluntary Reliability Guideline on Primary Frequency Control that encourages generators to provide a sustained and effective primary frequency response. If NERC recognized that generators were not providing primary frequency response as far back as 2010, NERC should support changes to the BAL-003 to obligate GO/GOPs to enable compliance.

There is compelling evidence and testimony from multiple sources—BAs, transmission operators, and NERC reports—to show that generators, a major source of primary frequency response, are not providing the appropriate response to frequency excursions. There is no “mechanism” available to the BAAs to compel generators to provide the necessary primary frequency response during an event. BAL-003 must be revised to address this.

Assumptions Behind the Current Standard:

BAL-003 appears to assume that all BAAs have the same composition and operate in the same manner. This may accurately describe the Eastern Interconnection. However, the Western Interconnection encompasses 38 BAAs that differ widely from one another.

Within the Western Interconnection, some BAAs are generation only, with 100% wind generation; some are generation only with 100% thermal generation; others serve load, with 100% hydro generation; and there are many other combinations.

BAL-003 rests on the assumption that as one BAA fails, the statistical probability is that other BAAs will provide sufficient excess response. But generation-only BAAs are driven by market

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conditions, which do not correlate to the timing of frequency events. BAL-003 allocates IFRO using a formula that has no bearing on a BAA’s ability to provide frequency response. In addition, the formula uses two-year-old data to allocate IFRO. A generation-only BAA is driven by real-time conditions, not by two-year old data.

In addition, BAL-003 does a poor job of recognizing and accommodating BAA changes over time. The single largest Western Interconnection BAA (CAISO) has experienced significant changes related rooftop solar. With the installation of rooftop solar, CAISO’s calculated load has decreased by over 5,000 MW, along with the reduction of the BAA calculated generation by over 5,000 MW. Under the formula to allocate IFRO, the presence of rooftop solar will reduce CAISO’s FRO. At the same time, rooftop solar provides no inertia to support frequency response. Allowing large offsets from rooftop solar to reduce FRO runs counter to reliability, unfairly burdening and imposing disparate treatment on remaining BAAs. The unintended consequence is to encourage BAAs to increase the how much of their generation is behind the meter, thereby reducing their allocations of FRO. NERC’s reliability standards should treat similarly situated responsible entities comparably, not create disparities among them. BAL-003 lacks flexibility to address real-time changes and real-time reliability requirements.

There is also no provision in the standard for generation that moves from one BAA to another. The BAA that lost the generation will still be held to a larger FRO than is justified by the amount of generation left in the BAA and the FRO of the attaining BAA will not change based on the increase in the amount of generation in the BAA.

Goal of a Reliability Standard

The foregoing discussion is not meant to imply that BAL-003 is completely without merit. It has brought frequency response to the forefront of many operational discussions. Some BAA operators have already taken steps to improve machine capability, change dispatch, and acquire Frequency Response Transfer from BAAs with excess. BAL-003 has moved the industry forward in its knowledge of frequency response. At the same time, it misaligns incentives for compliance and what is actually needed for reliability. This misalignment potentially drives progress in equipment, operations, and markets in the wrong direction.

To better ensure reliability, BAL-003 standard should:

• Address real-time reliability and not rely upon historical analysis and median performance. The standard needs to be flexible to address differing conditions and future changes.

• Ensure frequency response occurs to arrest rapid frequency decline and prevent underfrequency load shedding.

• Avoid unintended consequences, such as encouraging BAAs to time their response well after Point C and in the measurement period (Point B)

• Require testing of frequency responsive equipment

11

• Ensure comparability among all responsible entities needed for primary frequency response

SUMMARY Real-Time Reliability

• BAL-003 as currently configured does not require response to an event. Frequency response is needed 24 hours a day, 365 day a year to manage variations in Interconnection frequency.

• Historical event-driven analysis does not ensure frequency response is available in real-time.

• Because the current standard measures historical response, and is measured by performance at the median event, the Interconnection could experience underfrequency load shedding in real-time without any compliance failures.

• The allocation of IFRO is predicated on two-year-old information, which does not reflect the Interconnection’s frequency response needs in real-time.

• When a significant amount of generation trips off-line, frequency response is necessary within the first 20 seconds to arrest and stabilize rapid frequency decline. BAL-003 measures the average frequency support in the 20 to 52 second period following the event, which encourages BAAs to delay response to improve compliance. This subverts the primary purpose of the standard, and could drive less real-time reliability, not more.

Event Selection

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

• Frequency response is mechanically driven, and can be accurately measured only during machine movement.

Measurement

• The current standard uses Net Interchange Actual (NIA) to measure compliance. To have good measurement, one must have good statistics to support the values measured.

• NIA is made up of several variables, changes in load, changes in generation, changes in purchases, pseudo-tie values, changes in transmission flows and losses, frequency response, and others. Statistical analysis can support measurement only when all inputs can be determined to isolate the value being measured for compliance. NIA has far too many variables, all changing at the same time, to be treated as the sole measure of frequency response.

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

12

• Battery insertion or other responsive measures can be timed to occur in the measurement period thereby missing the arrestment period and subverting the purpose of the standard.

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

Assumptions Behind Current Standard

• BAL-003 appears to assume that all BAAs have the same composition and operate in the same manner. This may accurately describe the Eastern Interconnection. However, the Western Interconnection encompasses 38 BAAs that differ widely from one another.

• 100% generation only, wind only, 100% hydro base, 100% thermal base, many different mixtures

• The standard fails to recognize the changes associated with solar, and impacts associated with behind-the-meter solar. The allocation formula rewards a BAA with behind-the-meter solar and places the burden of frequency response on the remaining BAAs.


Request for Interpretation and Standard Authorization Request for PRC-024-2 Action Reject both the Request for Interpretation (RFI) and Standard Authorization Request (SAR) of PRC-024-2 submitted by Nuclear Energy Institute-NERC Issues Task Force (NEI-NITF), and provide a written explanation to the submitter within 10 days of the decision. Background NEI-NITF submitted a RFI and a SAR, one proposing to interpret the standard, and another to revise. In this instance, both are being recommended for rejection. The detail for each recommendation is addressed separately below. The RFI Pursuant to Section 7.0 of the Standard Processes Manual (SPM), NERC staff recommends that the Standards Committee (SC) reject the RFI on the grounds that the meaning of the Reliability Standard language at issue has been addressed in the development record of the standard, and the RFI is seeking a determination as to whether particular implementation approaches are compliant. Section 7.0 of the SPM states, in part,

A valid Interpretation request is one that requests additional clarity about one or more Requirements in approved NERC Reliability Standards, but does not request approval as to how to comply with one or more Requirements. A valid Interpretation response provides additional clarity about one or more Requirements, but does not expand on any Requirement and does not explain how to comply with any Requirement.1

Section 7.0 provides a number of examples of the grounds for which the SC is authorized to reject an RFI. Among other things, the SC may reject an RFI where: (1) it “[r]equests approval of a particular compliance approach”2; or (2) “[w]here a question has already been addressed in the record.”3 NEI-NITF’s RFI seeks clarification on whether auxiliary system protection systems trips are excluded from PRC-024. NERC staff has discussed this RFI with NEI-NITF, and it agrees the proper avenue for this clarification is Implementation Guidance, since it is seeking an assurance from Compliance that certain equipment will not be brought into the scope of a future audit.

1 See NERC Rules of Procedure, Appendix 3A, Standard Processes Manual at p. 30. 2 Id. 3 Id.

Further, the development record shows the question presented was addressed by the standard drafting team (SDT). The response to comments reflect the SDT did not include auxiliary relays.4 The SAR Pursuant to Section 4.1 of the SPM, NERC staff recommends that the SC reject the SAR. There is good cause to reject the SAR because the issue SAR clearly asks for “guidance” on the application of PRC-024. Section 4.1 of the SPM states a SAR should “document the scope and reliability benefit of a proposed project for one or more new or modified Reliability Standards or definitions or the benefit of retiring one or more approved Reliability Standards,” and it allows the SC to reject a SAR for “good cause.”5 The SAR submitted by NEI-NITF does not provide a proposed reliability benefit for modifying the existing standard. Rather, NEI-NITF states the purpose of the SAR is to “[p]rovide clear guidance on the applicability of PRC-024-2.”6 For the reasons stated above, NERC staff recommends that the SC reject both the SAR and RFI. If the SC rejects the RFI, it shall provide a written explanation for rejection to the entity submitting the RFI within 10 business days of the decision to reject. If the SC rejects the SAR, it shall provide a written explanation for rejection to the sponsor within 10 days of the rejection decision.

4 See e.g., general comment response to numerous auxiliary relay concerns: “The SDT has modified the standard to address those relays that have frequency or voltage inputs that would directly trip the unit” [emphasis added]. http://www.nerc.com/pa/Stand/Prjct201401StdrdsAppDispGenRes/Comment%20Report2_MedPri_2014-01-DGR_clean_2015_01_12.pdf 5 Id. at 17. 6 See NEI-NITF SAR at p.2.

http://www.nerc.com/pa/Stand/Prjct201401StdrdsAppDispGenRes/Comment%20Report2_MedPri_2014-01-DGR_clean_2015_01_12.pdf

http://www.nerc.com/pa/Stand/Prjct201401StdrdsAppDispGenRes/Comment%20Report2_MedPri_2014-01-DGR_clean_2015_01_12.pdf




Title of Proposed Standard: PRC-024-2, "Generator Frequency and Voltage Protective Relay Settings"



Name: Alison Mackellar

Organization: NEI-NITF (Nuclear Energy Institute – NERC Issues Task Force)

Telephone: 630-657-2817 Email: [email protected]


New Standard



Urgent Action

SAR Information


Nuclear Energy Institute NERC Issues Task Force (NEI/NITF) requests that NERC evaluate the interpretation of the requirements listed in NERC Standard PRC-024-2, "Generator Frequency and Voltage Protective Relay Settings;" specifically, Requirements R1, R2 and R3 of this Standard. While Requirements R1 and R2 appear to be clear in that they require Main Generator frequency and voltage protective relaying (including but not limited to voltage protective functions for discrete relays, volts per hertz relays, multi-function protective devices or protective functions within control systems) to be set so they do not trip within the no-trip zone of the curves in Attachments 1 and 2, the NEI-NITF


[email protected]




SAR Information noted that there was no acknowledgement or guidance related to generator trips that could result from a generating plant's auxiliary equipment protection systems (either directly or via tripping signals) and whether they are with the intended scope and therefore subjected to such ride through requirements. At a nuclear generating unit there may be auxiliary equipment protection systems that may not meet the criteria required in PRC-024-2 and may not have an explicit regulatory exemption. Examples of such equipment may include the large synchronous motor protection systems (e.g., circulating water pumps, reactor coolant pumps) or reactor protection system power supply motor generator protection systems. Purpose or Goal (How does this request propose to address the problem described above?):

Provide clear guidance on applicability of PRC-024-2 Requirements R1, R2 and R3 to trips resulting from auxiliary system protection systems.


The purpose of PRC-024-2 is to ensure Generator Owners set their generator protective relays such that generating units remain connected during defined frequency and voltage excursions. Brief Description (Provide a paragraph that describes the scope of this standard action.)

Revise PRC-024-2 Requirements R1, R2 and R3 to provide clear guidance on applicability to trips resulting from auxiliary protection systems. In addition, provide example evaluations for voltage and frequency protection relay settings to supplement the "Evaluating Protective Relay Settings" section of PRC-024-2.


Nuclear Energy Institute NERC Issues Task Force (NEI/NITF) requests that NERC evaluate the interpretation of the requirements listed in NERC Standard PRC-024-2, "Generator Frequency and Voltage Protective Relay Settings;" specifically, Requirements R1, R2 and R3 of this Standard. While Requirements R1 and R2 appear to be clear in that they require Main Generator frequency and voltage protective relaying (including but not limited to voltage protective functions for discrete relays, volts per hertz relays, multi-function protective devices or protective functions within control systems) to be set so they do not trip within the no-trip zone of the curves in Attachments 1 and 2, the NEI-NITF noted that there was no acknowledgement or guidance related to generator trips that could result from a


SAR Information generating plant's auxiliary equipment protection systems (either directly or via tripping signals) and whether they are with the intended scope and therefore subjected to such ride through requirements. At a nuclear generating unit there may be auxiliary equipment protection systems that may not meet the criteria required in PRC-024-2 and may not have an explicit regulatory exemption. Examples of such equipment may include the large synchronous motor protection systems (e.g., circulating water pumps, reactor coolant pumps) or reactor protection system power supply motor generator protection systems. The NEI-NITF requests the following clarifications from NERC in a revision to this Standard: • Specifically state if trips resulting from auxiliary system protection systems are excluded from the

PRC-024-2 Requirements R1, R2 and R3.

• Provide example evaluations for voltage and frequency protection relay settings to supplement the "Evaluating Protective Relay Settings" section of PRC-024-2.

Given the potential impact to design margin at a nuclear generating unit and financial impact to implement protective relay setting changes, it is imperative that the nuclear generating units are provided clear guidance on the scope of PRC-024-2.















Enter

(yes/no)


Yes


Yes


Yes


Yes

Related Standards



Related SARs

SAR ID Explanation

Regional Variances

Region Explanation

ERCOT

FRCC

MRO

NPCC

RFC

SERC

SPP

WECC


Version History Version Date Owner Change Tracking



Note: an Interpretation cannot be used to change a standard.

Interpretation 2010-xx: Request for an Interpretation of [Insert Standard Number], Requirement Rx, for [Insert Name of Company]

Date submitted: 11-17-16

Contact information for person requesting the interpretation:

Name: Alison Mackellar

Organization: NEI-NITF (Nuclear Energy Institute – NERC Issues Task Force)

Telephone: 630-657-2817

Email: [email protected]

Identify the standard that needs clarification:

Standard Number (include version number): PRC-024-2

(example: PRC-001-1)

Standard Title: "Generator Frequency and Voltage Protective Relay Settings"

Identify specifically what requirement needs clarification:

Requirement Number and Text of Requirement: Requirements R1, R2 and R3

Clarification needed: Need to provide clear guidance on applicability of PRC-24-2 Requirements R1, R2 and R3 to trips resulting from auxiliary system protection systems.

While Requirements R1 and R2 appear to be clear in that they require Main Generator frequency and voltage protective relaying (including but not limited to voltage protective functions for discrete relays, volts per hertz relays, multi-function protective devices or protective functions within control systems) to be set so they do not trip within the no-trip zone of the curves in Attachments 1 and 2, there is no acknowledgement or guidance related to generator trips that could result from a generating plant's auxiliary equipment protection systems (either directly or via tripping signals) and whether they are with the intended scope and therefore subjected to such ride through requirements.

At a nuclear generating unit there may be auxiliary equipment protection systems that may not meet the criteria required in PRC-024-2 and may not have an explicit regulatory exemption. Examples of such equipment may include the large synchronous motor protection systems (e.g., circulating water pumps, reactor coolant pumps) or reactor protection system power supply motor generator protection systems.

The NEI-NITF requests the following clarifications from NERC in an interpretation to this Standard:

When completed, email this form to: [email protected]


Request for Interpretation 2

• Specifically state if trips resulting from auxiliary system protection systems are excluded

from the PRC-024-2 Requirements R1, R2 and R3.

• Provide example evaluations for voltage and frequency protection relay settings to supplement the "Evaluating Protective Relay Settings" section of PRC-024-2.

Identify the material impact associated with this interpretation:

Identify the material impact to your organization or others caused by the lack of clarity or an incorrect interpretation of this standard.

At a nuclear generating unit there may be auxiliary equipment protection systems that may not meet the criteria required in PRC-024-2 and may not have an explicit regulatory exemption. Examples of such equipment may include the large synchronous motor protection systems (e.g., circulating water pumps, reactor coolant pumps) or reactor protection system power supply motor generator protection systems.

Given the potential impact to design margin at a nuclear generating unit and financial impact to implement protective relay setting changes, it is imperative that the nuclear generating units are provided clear guidance on the scope of PRC-024-2.


1 April 22, 2011

1 May 27, 2014 Standards Information Staff Updated template and email address for submittal.


Standard Authorization Request of INT-004-3.1

Action Reject the Standard Authorization Request (SAR) of INT-004-3.1 submitted by Gridforce Energy Management, L.L.C (Gridforce), and provide a written explanation to the submitter within 10 business days of the decision. Background Pursuant to Section 4.1 of the Standard Processes Manual (SPM), NERC staff recommends that the Standards Committee (SC) reject the SAR for good cause. Section 4.1 of the SPM states a SAR will “document the scope and reliability benefit of a proposed project for one or more new or modified Reliability Standards or definitions or the benefit of retiring one or more approved Reliability Standards,” and the SC may reject the SAR for “good cause.” 1 The Gridforce SAR centers on the removal of Purchasing-Selling Entities (PSEs) from the registration criteria that was approved in 2015.2 However, the requirements that still reference PSEs are already effectively retired.3 Further, a periodic review has recently commenced for the INT-004 standard, and any issues from the SAR will be forwarded to the periodic review team. For the reasons stated above, NERC staff recommends that the SC reject the SAR for good cause.

1 See NERC Rules of Procedure, Appendix 3A, Standard Processes Manual at p. 16. 2 See Order on Electric Reliability Organization Risk Based Registration Initiative, 150 FERC ¶ 61,213 (2015), available at https://www.ferc.gov/whats-new/comm-meet/2015/031915/E-3.pdf. 3 See Petition of the North American Electric Reliability Corp. for Approval of Risk-Based Registration Initiative Rules of Procedure Revisions, Dkt. No. RR15-4-000 (Dec. 11, 2014) at 21 (“The removal of Purchasing-Selling Entities as a functional entity would effectively retire Requirements R1 and R2 of Reliability Standard INT-004-3…”).

https://www.ferc.gov/whats-new/comm-meet/2015/031915/E-3.pdf




Title of Proposed Standard: Dynamic Transfers (INT-004-3.1)



Name: David Jones

Organization: Gridforce Energy Management, L.L.C.



New Standard



Urgent Action

SAR Information


1. As written, INT-004-3.1 assigns compliance requirements (R1 and R2 of the Standard) to the PSE, which is not a Reliability Entity under the NERC Risk-based model, making those requirements null and void, and thereby negating any positive contribution to the stated purpose of the Standard.

The stated purpose of INT-004 is to ensure that dynamic transfers are communicated and taken into account when planning and implementing Transmission Congestion Management procedures. This Standard, as written, does not ensure that the stated purpose is met, as two of the three compliance


[email protected]




SAR Information

requirements of the Standard (R1 and R2) are assigned to the PSE, which makes this Standard unenforceable.

2. As written, INT-004-3.1 requires Balancing Authorities to register all pseudo-ties in the NAESB Electric Industry Registry which, in and of itself, does nothing to ensure the pseudo-ties are included in Congestion Management procedures.

Again, this Requirement does not ensure the stated purpose of the Standard is met. Furthermore, the NAESB Registry is a commercial registry which has no qualifying reliability requirements. Finally, the Standard, as written, does not acknowledge historical programs using pseudo-ties that already contain proven alternative methods of inclusion in Congestion Management procedures.


Retire INT-004-3.1 or, alternatively, revise the existing Standard.


The objective of INT-004-3.1 should remain unchanged; specifically, “To ensure Dynamic Schedules and Pseudo-Ties are communicated and accounted for appropriately in congestion management procedures.”


Modification or Retirement of INT-004-3.1 is required because

a.) the PSE is no longer a Functional Entity in the NERC Risk-based model, thereby negating Requirements 1 and 2 of the Standard, and

b.) Inclusion of pseudo-ties in the NAESB Registry (Requirement 3) does not ensure the stated objective of the Standard (to ensure Dynamic Transfers are included in Congestion Management procedures).


INT-004-3.2 should have a single requirement stated as follows:

1.) Each Balancing Authority shall only implement or operate a Dynamic Transfer (Dynamic Schedule or Pseudo-tie) to serve Load for which one (or more) of the following conditions is met:


SAR Information

a.) a Request for Interchange is submitted as an on-time Arranged Interchange to the Sink Balancing Authority for that Dynamic Schedule or Pseudo-Tie, or

b.) the information about the Pseudo-Tie is included in congestion management procedure(s) via an alternate method.

INT-004 should have a single measure stated as follows:

1.) The Balancing Authority shall have evidence that it only implemented or operated Dynamic Transfers to serve load for which one (or more) of the following conditions were met: a.) a Request for Interchange was submitted as an on-time Arranged Interchange to the Sink

Balancing Authority for that Dynamic Schedule or Pseudo-Tie, or b.) the information about the Pseudo-Tie was included in congestion management procedure(s)

via an alternate method.

This removes the PSE from the Requirements in the Standard, accounts for Dynamic Transfers associated with programs that already include Congestion Management procedures (via the statement “the information about the Pseudo-Tie is included in congestion management procedure(s) via an alternate method”), and facilitates communication and coordination of all Dynamic Transfers.















Enter

(yes/no)


YES


YES


YES


YES

Related Standards



Related SARs

SAR ID Explanation

Regional Variances

Region Explanation

ERCOT

FRCC

MRO

NPCC

RFC

SERC

SPP

WECC


Request for Interpretation of PRC-024-2

Action Reject the Request for Interpretation (RFI) of PRC-024-2 submitted by California Independent System Operator (ISO), and provide a written explanation to the submitter within 10 business days of the decision. Background Pursuant to Section 7.0 of the Standard Processes Manual, NERC staff recommends that the RFI be rejected on the grounds that the question has already been addressed in the record and the meaning of the Reliability Standard is plain on its face. Section 7.0 of the Standard Processes Manual states, in part,

The entity requesting the Interpretation shall submit a Request for Interpretation form to the NERC Reliability Standards Staff explaining the clarification required, the specific circumstances surrounding the request, and the impact of not having the Interpretation provided. The NERC Reliability Standards and Legal Staffs shall review the request for interpretation to determine whether it meets the requirements for a valid interpretation. Based on this review, the NERC Standards and Legal Staffs shall make a recommendation to the Standards Committee whether to accept the request for Interpretation and move forward in responding to the Interpretation request.

Section 7.0 identifies the grounds upon which the Standards Committee (SC) is authorized to reject an RFI. Reasons for rejecting an RFI include “[w]here a question has already been addressed in the record” and “[w]here the meaning of a Reliability Standard is plain on its face.”1 In this instance, the clarification California ISO seeks (specifically, that voltage excursions outside the PRC-024-2 requirement’s specified “no trip zone” do not mean that a generator “must trip”) is unnecessary as the development record and the plain language of the standard are both clear that the requirement language details requirements around the “no trip zone” and does not otherwise create an opposite “must trip” zone. The RFI submitted by California ISO requests clarification of PRC-024-2’s Requirment R1 and R2, along with their associated Attachment 1 and Attachment 2, respectively. Requirement R1 and R2 specify that generating units must set protective relaying in such a manner that it does not trip the generating unit within a “no trip zone” outlined in the associated Attachment 1 and Attachment 2. California ISO seeks to clarify that PRC-024-2 does not require tripping outside of the “no trip zone.” The Reliability Standard and record of Project 2007-09 Generator Verification are clear that PRC-024-2 does not create a “must trip” obligation outside of the “no trip zone.” The 1 See NERC Rules of Procedure, Appendix 3A: Standard Processes Manual at p. 30.

development record supports that the standard is limited to the no trip zone; no area outside the curve of a ‘no trip zone’ is ever discussed. There was never a creation of a “must trip” scenario either. Therefore, an Interpretation is not necessary. NERC Standards staff and the leadership of the Project 2007-09 standard drafting team have also reviewed the RFI and agree that Reliability Standard PRC-024-2 permits instantaneous tripping, but it does not require instantaneous tripping in the scenario outlined by California ISO. Indeed, recent events and best practices support a preference that protective relaying not be set to instantaneously trip in that circumstance. More specifically, Attachment 1 outlines the off-nominal frequency capability curve and provides tables for each interconnection that explicitly describes the “no trip zone.” Within the off-nominal frequency capability curve, a “no trip zone” is specified, clarifying this does not include the lines. The x-axis of this curve is logarithmic and starts at 0.1 seconds. The accompanying table in Attachment 1 shows the trip levels and times in tabular format. The table permits instantaneous trip for frequencies less than or equal to 57 Hz or greater than or equal to 61.7 Hz. The language of Requirement R1 states that the Generator Owner shall set its frequency protective relaying “such that the generator frequency protective relaying does not trip the applicable generating unit(s) within the “no trip zone” of PRC-024 Attachment 1” as shown below. The requirement does not state where or how the frequency protective relaying must be set outside of the “no trip zone” in Attachment 1.

For the reasons stated above, NERC staff recommends that the SC reject the RFI. Under Section 7.0, if the SC rejects the RFI, the committee shall provide a written explanation for rejection to the entity submitting the RFI within 10 business days of the decision to reject. If the SC accepts the RFI request, the NERC Standards staff shall (i) form a ballot pool and (ii) assemble an Interpretation drafting team with the relevant expertise to address the interpretation for approval by the SC.

Note: an Interpretation cannot be used to change a standard.

Interpretation 2010-xx: Request for an Interpretation of [Insert Standard Number], Requirement Rx, for [Insert Name of Company]

Date submitted: March 9, 2017

Contact information for person requesting the interpretation:

Name: Richard Vine

Organization: California ISO

Telephone: 916-608-5722

Email: [email protected]

Identify the standard that needs clarification:

Standard Number (include version number): PRC-024-2

(example: PRC-001-1)

Standard Title: Generator Frequency and Voltage Protective Relay Settings

Identify specifically what requirement needs clarification:

Requirement Number and Text of Requirement:

R1. Each Generator Owner that has generator frequency protective relaying activated to trip its applicable generating unit(s) shall set its protective relaying such that the generator frequency protective relaying does not trip the applicable generating unit(s) within the “no trip zone” of PRC-024 Attachment 1.

R2. Each Generator Owner that has generator voltage protective relaying activated to trip its applicable generating unit(s) shall set its protective relaying such that the generator voltage protective relaying does not trip the applicable generating unit(s) as a result of a voltage excursion (at the point of interconnection) caused by an event on the transmission system external to the generating plant that remains within the “no trip zone” of PRC-024 Attachment 2.

Clarification needed: The California ISO requests clarification on Attachment 1 and Attachment 2 for the Western Interconnection.

Attachment 1 provides the following timetable for voltage trips:

Frequency (Hz) >= 61.7 Time (Sec) Instantaneous Trip

Frequency (HZ) <= 57.0 Time (Sec) Instantaneous Trip

When completed, email this form to: [email protected]

Agenda Item 15(i)Standards CommitteeJuly 19, 2017

Document Title 2

Further, in Attachment 2, the following is included:

Voltage (pu) >= 1.200 Time (sec) Instantaneous Trip

The California ISO seeks clarification that PRC-024-2 permits instantaneous tripping, but does not require instantaneous tripping.

Statement: The California ISO has observed that Generators that choose to enable frequency and/or high voltage protection are setting the protective functions at the noted set points with instantaneous trips, i.e., with no intentional time delay. The California ISO believes the Generators are following this course of action because the Generators believe that the Standard requires an instantaneous trip. The California ISO believes this interpretation is incorrect.

The reason for the California ISO’s interpretation is based on footnote 1 in the Standard, which states “Each Generator Owner is not required to have frequency or voltage protective relaying (including but not limited to frequency and voltage protective functions for discrete relays, volts per hertz relays evaluated at nominal frequency, multi-function protective devices or protective functions within control systems that directly trip or provide tripping signals to the generator based on frequency or voltage inputs) installed or activated on its unit.” Because high voltage and/or frequency relaying is not required, it follows that instantaneous tripping is permitted but not required because then relays would be required in order to provide instantaneous protection.

Identify the material impact associated with this interpretation:

Recently, the California ISO has experienced large blocks of solar-PV-based generation tripping offline for faults occurring on the high voltage transmission system. The amount of generation lost has ranged from 30 MW to 1,100 MW. These generators tripped for faults on the high voltage transmission system (500 kV and 220 kV) for frequency deviations at the “Instantaneous Trip” level in Attachment 1 of PRC-024-2. However, transmission operators cleared all faults in four cycles or fewer, obviating the need for these generators to trip at all. Preliminary analysis indicates that many of the inverters tripped instantaneously with frequency or voltage targets as recorded in the inverter codes.

If the Generators understand that they are not required to trip instantaneously under PRC-024-2, they can program a short time delay of six cycles instead of instantaneous tripping for these deviations. This will provide time for transmission line faults to clear and preserve generation.

As a long-term measure, the California ISO plans to actively participate with NERC, WECC, utilities, and inverter manufacturers to improve inverter protection performance during transient fault conditions.

Version History

Version Date Owner Change Tracking 1 March 9, 2017 California ISO

Document Title 3


Standard Authorization Request for CIP-014-3

Action Authorize the posting of a Standard Authorization Request (SAR) for Project 2017-08 for a 30-day formal comment period. Authorize the posting for nominations of a Project 2017-08 SAR drafting team for a 14-day nomination period.

Background NERC received a SAR from Utility Services, Inc. proposing modifications to CIP-014-2 to address a specific scenario related to timing of performance for newly applicable entities that is not otherwise addressed in the Reliability Standard or its Implementation Plan. At the time the SAR was submitted, CIP-014-2 had just become effective, and entities were performing implementation activities in support of the Reliability Standard’s requirements throughout 2016. Since the issue presented in the SAR represented a potential future applicability question, NERC staff and Utility Services agreed that it was prudent to coordinate proceeding with consideration of the SAR until after the initial implementation period of CIP-014-2 in an effort to avoid confusion with other implementation activities. While information indicates that the circumstances presented in the SAR likely do not currently apply to any entity, NERC staff and Utility Services agree that the scenario may manifest itself in the future and should be clarified in the Reliability Standard or the Implementation Plan. The issues identified within the SAR relate to when Transmission Owners, who newly identify that they are applicable to the standard, have to complete their initial risk assessment under Requirement R1. CIP-014-2 and the associated Implementation Plan do not specify when a Transmission Owner must complete performance of Requirement R1 if the Transmission Owner only becomes an applicable entity under CIP-014-2 after the effective date of the standard (October 1, 2015). NERC staff recommends that the SAR be posted for a 30-day comment period. NERC staff further recommends posting a 14-day nomination period for a SAR drafting team to review comments and develop a final SAR. The SAR drafting team will revise the SAR, as necessary, including any revisions to account for the possibility of revising the implementation plan.




Title of Proposed Standard: CIP-014-3 - Physical Security



Name: Brian Robinson

Organization: Utility Services, Inc.



New Standard



Urgent Action

SAR Information


Clarify compliance dates for newly identified Transmission Owners which come under the applicability of the standard due to Transmission stations or substations planned beyond the 24 month planning horizon identified in R1 or at some other date as identified by the entities listed in 4.1.1.3 due to association with IROLs.


[email protected]




SAR Information


Revise CIP-014 to specify the time-frame for a Transmission Owner to conduct its first assessment following the determination that the Transmission Owner is newly identified to be applicable to the standard.


Revise standard CIP-014 as necessary to provide the clarifications regarding completion of the first assessment for newly identified Transmissions Owners being applicable to the standard


As presently written, Transmission Owners that gain applicability to the CIP-014 standard are not provided any implementation guidance to come into compliance with CIP-014. Clarification is required to provide TOs that have newly determined applicability to the standard an implementation window in order to achieve compliance with CIP-014.


Requirement 1 of NERC Reliability Standard CIP-014-1/2:Physical Security requires that applicable entities complete an initial and subsequent risk assessments within the time frames specified in the requirement and in accordance with the implementation plan. The Implementation Plan for CIP-014-1/2 does not contemplate new applicable Facility identifications following the initial “enforcement” date of the standard of October 1, 2015. The implementation plan for Requirement 1 states: “The initial risk assessment required by CIP‐014‐1/2, requirement R1, must be completed on or before the effective date of the standard. Subsequent risk assessments shall be performed according to the timelines specified in CIP‐014‐1/2, Requirement R1.”

Guidance is required for Entities that have identified applicable Facilities after the initial enforceability date of October 1, 2015. Transmission Owners may gain applicability for several reasons such as third party notifications (IROL) listed in 4.1.1.3.

Without guidance newly applicable entities may be deemed non-compliant with Requirement 1 of CIP-014-2 for not having a complete initial risk assessment as specified by the requirement. The Requirement is clear in the time frames to complete subsequent risk assessments following the initial assessment.

















Enter

(yes/no)


Yes


Yes


Yes

4. A reliability standard shall not require the public disclosure of commercially sensitive information. All market participants shall have equal opportunity to access commercially non-sensitive information that is required for compliance

Yes



with reliability standards.

Related Standards


N/A N/A

Related SARs

SAR ID Explanation

N/A N/A

Regional Variances

Region Explanation

ERCOT N/A

FRCC N/A


Regional Variances

MRO N/A

NPCC N/A

RFC N/A

SERC N/A

SPP N/A

WECC N/A

Version History

Version Date Owner Change Tracking



SCPS Work Plan Activities Document— July 19, 2017

Agenda Item 17b Standards Committee

July 19, 2017

Standards Committee Process Subcommittee Work Plan (SC Endorsed Project Scopes)

Task

General Scope of Task

Task Initiated

Target Completion

Status/Remarks

1. Revisions to NERC Standard Processes Manual (SPM)

a. Section 6: Processes for Conducting Field Tests and Collecting and Analyzing Data

b. Section 7: Process for Developing an Interpretation

c. Section 11.0: Process for Approving Supporting Documents

Team Lead: Pete Heidrich John Bussman Ben Li Jennifer Flandermeyer Steve Rueckert Chris Gowder Sean Bodkin Linn Oelker Guy Zito (consulting) Lauren Perotti (NERC Legal) Sean Cavote (NERC)

a. Develop and propose recommendations to the SC for revisions and/or modifications to the SC Charter Section 10 and Section 6 of the Standard Processes Manual (SPM), which will address the coordination and oversight involvements of the NERC technical committees.

b. Develop and propose recommendations to the SC for revisions and/or modifications to the Interpretation Process in Section 7 of the SPM which will improve the effectiveness and efficiency of (i) validation of a request for Interpretation (RFI), and (ii) development of an interpretation of an approved Reliability Standard or individual Requirement(s) within an approved Reliability Standard.

c. Develop and propose recommendations to the SC for revisions and/or modifications to the Technical Document Approval Process in Section 11 of the SPM.

July 2015

March 2017 (delayed to mid_2018)

Comments received from the first posting of the revised SPM are being reviewed, and responses to be drafted. A verbal report to the SC regarding next steps was provided at the June 14 SC meeting.

Ballot Name: NERC Standard Processes Manual Sections 2.1, 3.7, 6, 7, 8 & 11 IN 1 OT Voting Start Date: 4/24/2017 12:01:00 AM Voting End Date: 5/3/2017 8:00:00 PM Ballot Type: OT Ballot Activity: IN Ballot Series: 1 Total # Votes: 140 Total Ballot Pool: 179 Quorum: 78.21 Weighted Segment Value: 64.72

2. Review/Revise Periodic Review Assessment Template

Team Lead: Ruida Shu Jennifer Flandermeyer Laura Anderson Sean Bodkin

Review the current version of the periodic review template and revise it as appropriate

May 2017 September 2017

Scope approved by the SC at its June 14 meeting

SCPS Work Plan Activities Document—July 19, 2017

Task On Hold

None

SCPS Work Plan Activities Document—July 19, 2017

Proposed Task

None


NERC Legal and Regulatory Update May 30, 2017 – June 30, 2017

NERC FILINGS TO FERC SUBMITTED SINCE LAST SC UPDATE

FERC Docket

No. Filing Description FERC Submittal Date

RM13-11-000

Informational Filing of NERC Regarding the Light-Load Case Study of the Eastern Interconnection NERC submitted an informational filing in response to a Commission directive in Order No. 794.

6/30/2017

RM15-14-000

Remote Access Study of NERC NERC submitted a report providing the results of a study of the remote access protections required by NERC's Critical Infrastructure Protection (CIP) Reliability Standards.

6/30/2017

FERC ISSUANCES SINCE LAST SC UPDATE

UPCOMING FILING DATES

FERC Docket No. Filing Description Projected Filing

Date

Currently, no filings are scheduled for the month of July.

FERC Docket No. Issuance Description FERC Issuance

Date

None

https://elibrary.ferc.gov/idmws/search/eSave.asp?fd=5/30/2017&td=6/30/2017&cat=submittal,%20issuance&dkt=rm13%2D11&ft=fulltext&dsc=description

http://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/Eastern%20Interconnect%20Info%20Filing.pdf

http://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/Eastern%20Interconnect%20Info%20Filing.pdf

https://elibrary.ferc.gov/idmws/search/eSave.asp?fd=05/30/2017&td=6/30/2017&cat=submittal,%20issuance&dkt=rm15%2D14&ft=fulltext&dsc=description

http://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/Final%20PUBLIC%20Remote%20Access%20Study%20Report%206-30-2017.pdf

Standards Committee Expectations Approved by Standards Committee January 12, 2012

Background Standards Committee (SC) members are elected by members of their segment of the Registered Ballot Body, to help the SC fulfill its purpose. According to the Standards Committee Charter, the SC’s purpose is:

In compliance with the NERC Reliability Standards Development Procedure, the Standards Committee manages the NERC standards development process for the North American-wide reliability standards with the support of the NERC staff to achieve broad bulk power system reliability goals for the industry. The Standards Committee protects the integrity and credibility of the standards development process.

The purpose of this document is to outline the key considerations that each member of the SC must make in fulfilling his or her duties. Each member is accountable to the members of the Segment that elected them, other members of the SC, and the NERC Board of Trustees for carrying out their responsibilities in accordance with this document.

Expectations of Standards Committee Members

1. SC Members represent their segment, not their organization or personal views. Each member isexpected to identify and use mechanisms for being in contact with members of the segment inorder to maintain a current perspective of the views, concerns, and input from that segment. NERCcan provide mechanisms to support communications if an SC member requests such assistance.

2. SC Members base their decisions on what is best for reliability and must consider not only what isbest for their segment, but also what is in the best interest of the broader industry and reliability.

3. SC Members should make every effort to attend scheduled meetings, and when not available arerequired to identify and brief a proxy from the same segment. Standards Committee businesscannot be conducted in the absence of a quorum, and it is essential that each Standards Committeemake a commitment to being present.

4. SC Members should not leverage or attempt to leverage their position on the SC to influence theoutcome of standards projects.

5. The role of the Standards Committee is to manage the standards process and the quality of theoutput, not the technical content of standards.

Agenda Item 19a Standards Committee July 19, 2017

http://www.nerc.com/comm/SC/Documents/SC%20approved%20Item_7-Att_2_SC_Charter-SC_Approved_January_16_2013_Revised_11_26_13_clean.pdf

Agenda Item 19b Standards Committee July 19, 2017

Standards Committee Meeting Dates and Locations for 2017

The time for face-to-face meetings is based on the ‘local’ time zone. The time specified for all conference calls is based on Eastern Time.

• January 18, 2017 Conference Call (1:00 - 4:00 p.m.)

• March 15, 2017 WECC (10:00 a.m. – 3:00 p.m.)

• April 19, 2017 Conference Call (1:00 - 4:00 p.m.)

• June 14, 2017 Atlanta (10:00 a.m. – 3:00 p.m.)

• July 19, 2017 Conference Call (1:00 - 4:00 p.m.)

• September 7, 2017 MRO (10:00 a.m. – 3:00 p.m.)

• October 18, 2017 Conference Call (1:00 - 4:00 p.m.)

• December 6, 2017 Atlanta (10:00 a.m. – 3:00 p.m.)

This schedule was designed so that the SCPS SC subcommittee face-to-face meetings will occur the day before and the PMOS SC Subcommittee will occur face-to-face the mornings of the SC meetings from 8:00 a.m. – 9:45 a.m. Scheduling of subcommittee face-to-face meetings is handled by the chairs of the subcommittees in consultation with the subcommittees’ members and NERC staff.

Standards Committee 2017 Segment Representatives

Segment and Term Representative Organization

Chair 2016‐17

Brian Murphy Senior Attorney

NextEra Energy, Inc.

Vice‐Chair 2016‐17

Michelle D’Antuono Manager, Energy

Occidental Energy Ventures, LLC

Segment 1‐2016‐17 Laura Lee Manager of ERO Support and Event Analysis, System Operations

Duke Energy

Segment 1‐2017‐18 Sean Bodkin NERC Compliance Policy Manager

Dominion Resources Services, Inc.

Segment 2‐2016‐17 Ben Li Consultant

Independent Electric System Operator

Segment 2‐2017‐18 Charles Yeung Executive Director Interregional Affairs

Southwest Power Pool

Segment 3‐2016‐17 Scott Miller Manager Regulatory Policy

MEAG Power

Segment 3‐2017‐18 John Bussman Manager, Reliability Compliance

Associated Electric Cooperative, Inc.

Segment 4‐2016‐17 Chris Gowder Regulatory Compliance Manager

Florida Municipal Power Agency

Segment 4‐2017‐18 Barry Lawson Associate Director, Power Delivery and Reliability

National Rural Electric Cooperative Association

Segment 5‐2016‐17 Randy Crissman Vice President – Technical Compliance

New York Power Authority

Segment 5‐2017‐18 Amy Casuscelli Sr. Reliability Standards Analyst

Xcel Energy

Agenda Item 19c Standards Committee July 19, 2017

Segment 6‐2016‐17 Andrew Gallo Director, Reliability Compliance

City of Austin dba Austin Energy

Segment 6‐2017‐18 Brenda Hampton Regulatory Policy

Energy Future Holdings – Luminant Energy Company LLC

Segment 7‐2016‐17 Frank McElvain Senior Manager, Consulting

Siemens Power Technologies International

Segment 7‐2017‐18 vacant

Segment 8‐2016‐17 Robert Blohm, Managing Director

Keen Resources Ltd.

Segment 8‐2017‐18 David Kiguel Independent

Segment 9‐2016‐17 Alexander Vedvik Senior Electrical Engineer

Public Service Commission of Wisconsin

Segment 9‐2017‐18 Michael Marchand Senior Policy Analyst

Arkansas Pubic Service Commission

Segment 10‐2016‐17 Guy Zito Assistant Vice President of Standards

Northeast Power Coordinating Council

Segment 10‐2017‐18 Steve Rueckert Director of Standards

Western Electricity Coordinating Council

Standards Committee 2017 Roster

Parliamentary Procedures

Agenda Item 19d Standards Committee July 19, 2017

Based on Robert’s Rules of Order, Newly Revised, 11th Edition, plus “Organization and Procedures Manual for the NERC Standing Committees”

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.” The vote is subject to a 2/3 majority approval. Also, any member may call the question. This motion is not debatable. The vote is subject to a 2/3 vote.

Record each member’s vote on a Motion

Request a Roll Call Vote

No Takes precedence over main motion. No debate allowed, 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 to postpone 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 bring the 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 can not 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.

- 1 -

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 ensures that 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.

- 2 -

Voting Voting Method When Used How Recorded in Minutes Unanimous Consent The standard practice.

When the Chair senses that the Committee is substantially in agreement, and the Motion needed little or no debate. No actual vote is taken.

The minutes show “by unanimous consent.”

Vote by Voice The standard practice. The minutes show Approved or Not Approved (or Failed).

Vote by Show of Hands (tally)

To record the number of votes on each side when an issue has engendered substantial debate or appears to be divisive. Also used when a Voice Vote is inconclusive. (The Chair should ask for a Vote by Show of Hands when requested by a member).

The minutes show both vote totals, and then Approved or Not Approved (or Failed).

Vote by Roll Call To record each member’s vote. Each member is called upon by the Secretary, and the member indicates either “Yes,” “No,” or “Present” if abstaining.

The minutes will include the list of members, how each voted or abstained, and the vote totals. Those members for which a “Yes,” “No,” or “Present” is not shown are considered absent for the vote.

Notes on Voting (Recommendations from DMB, not necessarily Mr. Robert)

Abstentions. When a member abstains, he is not voting on the Motion, and his abstention is not counted in determining the results of the vote. The Chair should not ask for a tally of those who abstained.

Determining the results. The results of the vote (other than Unanimous Consent) are determined by dividing the votes in favor by the total votes cast. Abstentions are not counted in the vote and shall not be assumed to be on either side.

“Unanimous Approval.” Can only be determined by a Roll Call vote because the other methods do not determine whether every member attending the meeting was actually present when the vote was taken, or whether there were abstentions.

Majorities. Robert’s Rules use a simple majority (one more than half) as the default for most motions. NERC uses 2/3 majority for all motions.

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