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RSC October 2013 Meeting Item 0.0
Northeast Power Coordinating Council, Inc. (NPCC) Antitrust Compliance Guidelines
It is NPCC’s policy and practice to obey the antitrust laws and to avoid all conduct that unreasonably restrains competition. The antitrust laws make it important that meeting participants avoid discussion of topics that could result in charges of anti-competitive behavior, including: restraint of trade and conspiracies to monopolize, unfair or deceptive business acts or practices, price discrimination, division of markets, allocation of production, imposition of boycotts, exclusive dealing arrangements, and any other activity that unreasonably restrains competition.
It is the responsibility of every NPCC participant and employee who may in any way affect NPCC’s compliance with the antitrust laws to carry out this commitment.
Participants in NPCC activities (including those participating in its committees, task forces and subgroups) should refrain from discussing the following throughout any meeting or during any breaks (including NPCC meetings, conference calls and informal discussions):
• Industry-related topics considered sensitive or market intelligence in nature that are outside of their committee’s scope or assignment, or the published agenda for the meeting;
• Their company’s prices for products or services, or prices charged by their competitors; • Costs, discounts, terms of sale, profit margins or anything else that might affect prices; • The resale prices their customers should charge for products they sell them; • Allocating markets, customers, territories or products with their competitors; • Limiting production; • Whether or not to deal with any company; and • Any competitively sensitive information concerning their company or a competitor.
Any decisions or actions by NPCC as a result of such meetings will only be taken in the interest of promoting and maintaining the reliability and adequacy of the bulk power system. Any NPCC meeting participant or employee who is uncertain about the legal ramifications of a particular course of conduct or who has doubts or concerns about whether NPCC’s antitrust compliance policy is implicated in any situation should call NPCC’s Secretary, Andrianne S. Payson at 212-335-4765.
** Item in Meeting Material Page 1 of 9 RSC Agenda Last Saved 10/7/2013 10:01 AM
Note: For reference – Both the Glossary of Terms Used in NERC Reliability Standards, updated July 22, 2013, and the NPCC Glossary of Terms, updated May 2012, are included in the Meeting Materials**.
MEETING MINUTES Attendees:
Name Organization Sector Day(s) Comment 1. Guy Zito Northeast Power Coordinating Council 1 & 2 2. Lee Pedowicz Northeast Power Coordinating Council 1 & 2 3. Gerry Dunbar Northeast Power Coordinating Council 1 & 2 4. Damase Hebert Northeast Power Coordinating Council 1 & 2 5. Michael Lombardi Northeast Power Coordinating Council 1 & 2 6. Chris de Graffenried
Sector 3 Proxy for Peter Yost
Consolidated Edison Co. of NY, Inc. 1 / 3 1 & 2
7. Ben Wu Orange and Rockland Utilities 1 1 & 2 8. Si Truc Phan
Sector 1 Proxy for Sylvain Clermont
Hydro Québec TransÉnergie 1 / 2 1 & 2
9. Brian Shanahan National Grid 1 1 & 2 10. David Kiguel Hydro One Networks Inc. 1 1 & 2 11. Mark Kenny Northeast Utilities 1 1 12. Helen Lainis Independent Electricity System Operator 2 1 & 2 13. Kathleen Goodman ISO-NE 2 1 & 2 via phone 14. Donald Weaver New Brunswick System Operator 2 1 & 2 15. Greg Campoli New York Independent System Operator 2 1 & 2 16. Michael Jones National Grid 3 1 & 2 17. Mike Garton Dominion 4 1 & 2 via phone 18. David Ramkalawan Ontario Power Generation Incorporated 4 1 & 2 19. Christy Koncz PSEG Power 4 1 via phone 20. Herb Schrayshuen
Proxy for Silvia Parada Mitchell
Power Advisors, LLC – Proxy for NextEra Energy, LLC
4 1 & 2
NPCC REGIONAL STANDARDS COMMITTEE
AGENDA FOR MEETING #13-4 August 21, 2013, 10:00 a.m. - 5:00 p.m. ET August 22, 2013, 8:00 a.m. - 3:00 p.m. ET Hydro One, 483 Bay Street, Toronto, ON
Attire: Business Casual Dial-In: 719-785-1707 Guest Code 8287#
RSC October 2013 Meeting Item 2.1
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Name Organization Sector Day(s) Comment 21. Bruce Metruck New York Power Authority 5 1 via phone 22. Brian Robinson Utility Services 5 1 via phone 23. Diane Barney New York State Dept. of Public Service 6 1 via phone 24. Kal Ayoub FERC Guest 1 & 2 25. Howard Gugel NERC Guest 1 & 2 26. Don Nelson Guest 1 & 2 via phone 27. Ayesha Sabouba Hydro One Networks Inc. Guest 1 & 2 28. Sasa Maljukan Hydro One Networks Inc. Guest 1 & 2 29. Vijay Puran New York State Dept. of Public Service Guest 1 via phone 30. Joel Charlebois AESI Guest 1 & 2 31. Ben Li Independent Electricity System Operator Guest 1 & 2
- Guy Zito called the meeting to order at 10:00 AM on August 21, 2013.
- Mr. David Curtis, Director of the Hydro One Asset Strategy Division, welcomed the RSC to Toronto.
Introductions and Chair’s Remarks - Guy Zito noted that David Kiguel is retiring from Hydro One and that this would be his last
RSC meeting. Guy presented David a plaque in recognition and appreciation of David’s contributions over his tenure on the RSC. The RSC members wish David well in his retirement.
NPCC Antitrust Compliance Guidelines** - NPCC Antitrust Compliance Guidelines were read.
Agenda Items: 1.0 Review of Agenda - The review of the agenda noted that 13 standard development projects were currently posted by
NERC for industry review and / or ballot. The NERC Standard Developers for the posted projects had been contacted and would be calling into the RSC meeting to identify where in the process each project was and to answer any questions the RSC may have.
-
2.0 RSC Meeting Minutes 2.1 Approval of Minutes: June 19 & 20, 2013 RSC Meeting #13-3**
- The June 2013 meeting minutes were reviewed. A motion was made and seconded (by David Kiguel and Mike Jones, respectively) to approve the minutes as written. The motion passed.
3.0 Drafting Team Members and Executive Tracking Summary 3.1 NPCC Members on NERC Drafting Teams**
- The NERC Drafting Team participant spreadsheet was reviewed. 3.2 Executive Tracking Summary**
- The NERC Executive Tracking Summary (ETS) spreadsheet was reviewed. A new worksheet tab for NPCC Directory Interpretations was added to specifically track Directory Interpretations.
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3.3 PMOS Project Tracking Spreadsheet** - The NERC PMOS Project Tracking Sheet (a project tool used by the NERC Standards
Committee (SC) and its Project Management and Oversight Subcommittee (PMOS) to track the progress of NERC standards development projects) was included in the meeting materials for information.
4.0 Open Action Items** - The Open Action Items from previous RSC meetings were reviewed and status updates
provided. • The due date for Item 4.3, “PRC-005 Guidance - Investigate maintenance cycles that are
more stringent than those in the standard”, was moved to the next RSC meeting • Item 4.5, “Identify the filing requirements for the Canadian Provinces”, was updated as
completed. Don Weaver had previously provided the NBSO MOU which indicated that “NPCC shall notify the NBSO of regional reliability criteria adopted by NPCC.” At the August RSC meeting, Helen Lainis indicated that there is not any requirement for NPCC to notify Ontario of regional reliability criteria adopted by NPCC. However, Helen requested that NPCC notify Ontario of any new or revised NPCC criteria when approved by the NPCC BOT. This notification will trigger the IESO’s legislative requirement to post on its website new or revised NPCC criteria. Gerry Dunbar to incorporate Helen’s request into the process for filing completed directories. [Action]
• Reported as completed were Items1: 13-3.1, The NERC Drafting Team participant spreadsheet was reviewed and updated at
the meeting based on input from the NPCC Standards Staff and RSC Members 13-3.3, New York Adoption of More Stringent/Specific NPCC Criteria - Provide new
Completion Date 13-3.4, The NPCC CC will not perform a formal review of RSAWs - Request was made
that the RSC formally request the CC to respond 13-3.5, Gerry Dunbar to obtain agreement from Joint Task Force Chairs regarding
timeframe for task force actions 13-3.6, Gerry Dunbar to include an appeal process in the Directory Development and
Revision Manual 13-3.7, Gerry Dunbar will circulate the proposed responses to the RSC, respond to the
commenters from the open process, and re-post, circa mid-July, the revised Directory Development and Revision Manual for an additional open process comment period
13-3.9, Lee Pedowicz will email RC reps to determine if they have Short Circuit MVA values for buses in their footprint
13-3.10, A tracking document to keep a record of directory development activities, including interpretations, will be developed by Gerry Dunbar and included in the meeting materials for future RSC meetings
13-3.11, The interrelation between Agenda Items 11, 12 and 13 suggests that an alternate approach to present this data may be warranted. Michael Lombardi will propose a revised format at the next RSC meeting
1 Meeting action items are designated by the meeting number (e.g., 13-3 for the 3rd RSC meeting in 2013)
followed by a sequential number (e.g., 1, 2, 3, etc.)
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5.0 Items Requiring RSC Discussion / Approval 5.1 NPCC Directory Development and Revision Manual
- Gerry Dunbar reported on the latest revisions made to NPCC Directory Development and Revision Manual. The proposed revisions to the manual are posted for comment in the NPCC open process through 9/29/13.
5.2 NPCC Regional Standard Processes Manual (RSPM)** - Michael Lombardi discussed the disposition of the comments received during the NERC and the
NPCC posting of the NPCC Regional Standard Processes Manual (RSPM). A copy of the revised manual along with the disposition of the comments was included in the meeting materials. A key change in the latest proposed manual is the addition of an exit ramp to allow projects already in development to be curtailed due to changing circumstances or conditions. Another key change is the replacement of the NPCC interpretation process with the NPCC clarification process. A benefit of the NPCC clarification process is the elimination of both a NERC and NPCC process using the name “Interpretation” and thereby eliminating possible confusion. A motion was made and seconded (by Herb Schrayshuen and David Kiguel, respectively) to post the proposed revision to the NPCC Regional Standard Processes Manual (RSPM) for a 45-day comment period. The motion passed. Michael Lombardi shall post the proposed revision of the RSPM. [Action]
5.3 Standards Outreach - Guy Zito indicated that the NPCC Standards Staff is looking at options in developing a
Standards Outreach Program, e.g., conduct targeted meetings at entity locations. Entity suggestions and feedback is welcome. This agenda item will be discussed at the next RSC meeting.
6.0 NERC Reliability Standards http://www.nerc.com/pa/Stand/Pages/Standards-Under-Development.aspx
6.1 Currently Posted Projects** - The currently posted continent-wide projects were discussed along with a review of the
comments forms and all comments received by NPCC to date. The discussion of each of the projects reviewed was kicked-off by a NERC Standards Developer that called into the RSC meeting. The NERC Standards Developer provided an overview of the project (e.g., its purpose, where it is in development process as well as the next steps) and answered questions from the RSC members. Following the discussion with a NERC Standards Developer, the RSC members discussed each project and Lee Pedowicz added responses to the appropriate Comment Forms. Comments to be finalized before submission to NERC.
6.2 Ballot History (Since last RSC Meeting)** 6.3 Comment Form History (Since last RSC Meeting)**
Other Project 2013-03 Geomagnetic Disturbance Mitigation - A comment period and initial ballot for EOP-010-1, Geomagnetic Disturbance Operations,
concluded on 8/13/13. The GMD Drafting Team (DT) called into the RSC meeting and reported: • Standard Development Stage 1 will require applicable registered entities to develop and
implement Operating Procedures that can mitigate the effects of GMD events • Standard Development Stage 2 will require applicable registered entities to conduct
initial and on-going assessments of the potential impact of benchmark GMD events on
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their respective system. The benchmark GMD event has not been determined and will be undertaken as part of Stage 2.
• The proposed Stage 1 standard (EOP-010-1) is applicable to Balancing Authority Areas and Transmission Operator Areas that includes any transformer with high side terminal voltage greater than 200 kV
• GMD notification already exists in another standard (IRO-005-3.1a, R3) – GMD DT indicated it will leave GMD notification in place rather than pull it into EOP-010. [Subsequent to the August RSC meeting the GMD DT posted Draft 2 of EOP-010-1 which included a requirement for the RC to disseminate forecasted and current space weather information as specified in the RC Operating Plan. Rationale: The proposed EOP-010-1 requirement (R2) replaces IRO-005-3.1a, R3. IRO-005-4 has been adopted by the NERC Board and filed with FERC, and will retire IRO-005-3.1a R3.]
7.0 NERC Drafting Team Nominations** http://www.nerc.com/pa/Stand/Pages/Drafting-Team-Vacancies.aspx
- There are currently no Drafting team vacancies nor are there any open Informal Development Team Solicitations.
7.1 Currently Posted Drafting Team Vacancies 7.2 Closed Drafting Team Nominations (Since last RSC Meeting) 7.3 Solicitation For Informal Development Teams
8.0 NPCC Regional Reliability Standards** https://www.npcc.org/Standards/default.aspx
8.1 Current Activities: Regional Standards 8.2 Current Activities: Regional Standard Interpretations
- There are not any outstanding Regional Standards Interpretations in the queue. - Gerry Dunbar reported that a recent request from a wind farm facility sought clarification if
the applicability of PRC-006-NPCC-1 to generator underfrequency trip relays was location dependent. A reply to the requester indicated that the standard is applicable to generator underfrequency trip relays regardless of where the relays are located. Herb Schrayshuen asked how this information would be disseminated to the industry so that other generating facilities in NPCC’s footprint are made aware of the response. Gerry Dunbar will post the subject response, along with the other Regional Standards Interpretations, on the NPCC website. [Action]
9.0 NPCC Non-Standards** https://www.npcc.org/Standards/SitePages/NonStandardsList.aspx
9.1 Directories In Development 9.2 Directory Interpretations 9.3 Criteria (A) / Guides (B) / Procedures (C) Documents
10.0 RSC Member Items of Interest 10.1 Reliability Guideline: Operating Reserve Management – Comments due 8/31/13
The NERC Balancing Authority Reliability-based Controls Standard Drafting Team developed the Reliability Guideline: Operating Reserve Management. The guideline provides recommended practices for the management of an appropriate mix of Operating Reserve. It also provides guidance on the management of Operating Reserve required to meet the NERC Reliability Standards.
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10.2 Protection System Misoperation Section 1600 Data Request – Comments due 9/23/13 The revised Reliability Standard, PRC-004-3 – Protection System Misoperation Identification and Correction, is currently projected to be presented to the NERC Board of Trustees (Board) in November of 2013. The Standard Drafting Team proposes to remove the data reporting obligation from Reliability Standard PRC-004-2a and is instead proposing that NERC request the data needed for performance analysis purposes under Section 1600 of the NERC Rules of Procedure. The revised Reliability Standard PRC-004-3 standard will continue to require retention of data or evidence of compliance for audit and compliance purposes in the Compliance section of the standard. The draft data request and a sample reporting template have been posted for comment.
- It was not clear how the draft data request was distributed to the industry for comment. Howard Gugel (NERC) indicated he would follow up on this issue. Subsequent to the RSC meeting a NERC notification of Posting for Public Comment was distributed to the nerc-info list server.
11.0 Standards Activity Post NERC BOT Approval** (Since last RSC Meeting)
11.1 NERC Filings to FERC http://www.nerc.com/FilingsOrders/Pages/default.aspx
11.2 FERC Orders / Rules http://www.nerc.com/FilingsOrders/Pages/default.aspx
11.3 Federal Register https://www.federalregister.gov/
12.0 NERC Meetings 12.1 Standards Committee (SC) and Standards Committee Executive Committee (SCEC)
http://www.nerc.com/comm/SC/Pages/default.aspx Since Last RSC Meeting 12.1.1 Conference Call: July 18, 2013, 1:00 to 5:00 p.m. ET, Dial-in Number:
1.866-740-1260, Code: 5247071 Upcoming 12.1.2 Conference Call: August 22, 2013, 1:00 to 5:00 p.m. ET, Dial-in Number:
1.866-740-1260, Code: 5247071 12.1.3 Meeting: September 19, 2013 – Denver (8 a.m. to 5 p.m.) 12.1.4 Conference Call: October 17, 2013 conference call from 1 to 5 p.m. ET,
Dial-in Number: 1.866-740-1260, Code: 5247071 12.1.5 Conference Call: November 14, 2013 conference call from 1 to 5 p.m. ET,
Dial-in Number: 1.866-740-1260, Code: 5247071 12.1.6 Meeting: December 11-12, 2013 – Atlanta (1 to 5 p.m. December 11; 8 a.m.
to noon December 12)
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12.2 Standards Committee Process Subcommittee (SCPS) http://www.nerc.com/comm/SC/Pages/Standards%20Committee%20Process%20Subcommittee%20SCPS/Standards-Committee-Process-Subcommittee-SCPS.aspx
- A motion was made and seconded (by Herb Schrayshuen and David Kiguel, respectively) to provide feedback to the SCPS on the quality issues that are being found in the standards recently posted for comment and/or ballot. The Chair proposed that he handle the communication regarding standards quality with NERC. Chair to communicate with NERC regarding the issues found. [Action]
Since Last RSC Meeting 12.2.1 N/A Upcoming 12.2.2 Meeting: August 29, 2013, 8:00 a.m. to 5:00 p.m. ET, Tampa, FL 12.2.3 Meeting: September 18, 2013, 9:00 a.m. to 5:00 p.m. MT, Denver, CO 12.2.4 Meeting: December 11, 2013, 8:00 a.m. to 5:00 p.m. ET, Atlanta, GA
12.3 Standards Committee Project Management and Oversight Subcommittee (PMOS) http://www.nerc.com/comm/SC/Pages/ProjectManagementandOversightSubcommittee(PMOS).aspx
- A suggestion was made for PMOS to manage the posting of projects so that the Industry is not overwhelmed by a large volume of postings. Guy Zito, as a member of PMOS will take this suggestion to the next PMOS meeting.
Since Last RSC Meeting 12.3.1 Conference Call: July 29, 2013, 2:30 p.m. to 4:00 p.m. ET, Dial-in:
1.866.740.1260 | Access Code: 7686935 | Security Code: 072913 Upcoming 12.3.2 Meeting: September 18, 2013, 1:00 to 4:00 p.m. MT, Denver, CO 12.3.3 Conference Call: October 28, 2013, 2:30 p.m. to 4:00 p.m. ET, Dial-in:
1.866.740.1260 | Access Code: 7686935 | Security Code: 072913 12.3.4 Conference Call: November 18, 2013, 2:30 p.m. to 4:00 p.m. ET, Dial-in:
1.866.740.1260 | Access Code: 7686935 | Security Code: 072913 12.3.5 Meeting: December 11, 2013, 1:00 to 4:00 p.m. ET, Atlanta, GA
12.4 Member Representatives Committee (MRC) Meeting http://www.nerc.com/gov/bot/MRC/Pages/AgendaHighlightsandMinutes2013.aspx Since Last RSC Meeting 12.4.1 Informational Conference Call: July 17, 2013, 1:00 p.m. ET 12.4.2 Meeting: August 14, 2013, 1:00 to 5:00 p.m. ET, Montreal, QC
Cyber Security Standards Proposed Transition Guidance (Revised) Upcoming 12.4.3 Upcoming Meeting: November 6, 2013, 1:00 to 5:00 p.m. ET, Atlanta, GA
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12.5 Board of Trustees (BOT) Meeting http://www.nerc.com/gov/bot/Pages/Agenda-Highlights-and-Minutes-.aspx Since Last RSC Meeting 12.5.1 Meeting: August 15, 2013, 8:00 a.m. to 1:00 p.m. ET, Montreal, QC Upcoming 12.5.2 Upcoming Meeting: November 7, 2013, 8:00 a.m. to 1:00 p.m. ET, Atlanta,
GA 12.6 Reliability Issues Steering Committee (RISC)
http://www.nerc.com/comm/RISC/Pages/AgendasHighlightsandMinutes.aspx Since Last RSC Meeting 12.6.1 Meeting: July 11, 2013, 9:30 a.m. to 5:30 p.m. ET and July 12, 2013, 8:00
a.m. to noon ET, Washington, DC 12.6.2 Meeting: August 15, 2013, 12:30 p.m. to 1:30 p.m. ET, Montreal, QC (after
NERC BOT Meeting) Upcoming 12.6.3 RISC 2013 Leadership Summit: October 24, 2013, 8:30am – 4:30pm EDT 12.6.4 Meeting: October 25, 2013, 8:00am – 12:00pm EDT 12.6.5 Meeting: February 2014 (details TBD)
13.0 NERC Compliance Tools** (Since last RSC Meeting) 13.1 Compliance Application Notices (CANs)
http://www.nerc.com/pa/comp/Resources/Pages/Compliance-Application-Notices.aspx
13.2 Compliance Analysis Reports (CARs) http://www.nerc.com/pa/comp/Pages/Compliance-Analysis-Reports.aspx
13.3 Reliability Standard Audit Worksheets (RSAWs) http://www.nerc.com/pa/comp/Pages/Reliability-Standard-Audit-Worksheets-(RSAWs).aspx
14.0 NERC Items of Interest (Since last RSC Meeting) 14.1 Lessons Learned
http://www.nerc.com/pa/rrm/ea/Pages/Lessons-Learned.aspx 14.1.1 There were three Lessons Learned published since the last RSC Meeting.
The first two were published on July 2, 2013 and the third was published on July 25, 2013: LL20130701 - Current Transformer Ground Relay
Primary Interest Groups: Transmission Owners (TO), Transmission Operators (TOP)
LL20130702 - Transmission Relaying – Backup Ground Protection Primary Interest Groups: Transmission Owners (TO)
LL20130703 - Use Loading Resistors When Applying Solid State Contacts to High-Impedance Input Devices Primary Interest Groups: Generator Owners (GO), Generator Operators (GOP), Transmission Owners (TO), Transmission Operators (TOP)
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- In addition to the above, on 8/21/13 two new lessons learned were posted on the NERC website under the “Event Analysis – Lessons Learned” page: LL20130801 Inappropriate System Privileges Caused Loss of SCADA Monitoring LL20130802 Indistinguishable Screens during a Database Update Led to Loss of
SCADA Monitoring and Control 8/21/2013 14.2 Alerts
http://www.nerc.com/pa/rrm/bpsa/Pages/Alerts.aspx 14.2.1 There have not been any NERC Alerts released since the last RSC meeting
15.0 Other Items of Interest 15.1 NERC Reliability Standards and Compliance Workshop, Atlanta, GA, September 24,
2013 10:00 a.m. through September 26, 2013 Noon ET
15.2 NPCC 2013 Fall Compliance & Standards Workshop, Mystic, CT, November 20, 2013 9:00 a.m. through November 22, 2013 Noon ET
15.3 NPCC General Meeting, Boston, MA, December 4, 2013, 1:00m p.m. to 5:00 p.m. ET
15.4 Other Upcoming Events •
16.0 Future RSC Meetings and Conference Calls 16.1 RSC 2013/2014 Meeting Dates
October 9-10, 2013, Montreal Dec. 5-6, 2013 (General Meeting Dec. 4, 2013), Boston, Mass. Feb. 19-20, 2014, NextEra Energy Offices
16.2 RSC 2013 Conference Call Schedule all Calls are planned to start at 10:00 a.m. (call 719-785-1707, Guest Code 8287#)
September 6 September 20 October 4 October 25 November 8 November 22 December 20
Respectfully Submitted,
Guy V. Zito, Chair RSC Assistant Vice President-Standards Northeast Power Coordinating Council, Inc.
RSC October 2013 Meeting Item 3.1
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NPCC Representatives on NERC Standards Drafting Teams
Project No. Project Title DT Type NPCC Representatives Company Telephone E-mail Address
2006-02 Assess Transmission Future Needs & Develop Transmission Plans Standard Dana Walters New York Independent System Operator 518-356-8582 [email protected] Reliability Coordination Standard Earl Barber National Grid 315-428-5532 [email protected] Operating Personnel Communications Protocols Standard Tom Irvine Hydro One Networks 705-792-3004 [email protected] Real Time Operations Standard2007-06 System Protection Coordination Standard David Cirka National Grid 781-907-3240 [email protected]
Orville Cocking Con Edison 917-789-6885 [email protected] Morrell New York State Dept of Public Svc 518-486-7322 [email protected] Stenroos Florida Power & LightVenkat Kolluri EntergyVladimir Stanisic AESILee Pedowicz NPCC 212-840-1070 [email protected] Stanisic AESI
2007-12 Frequency Response Standard Mike Potishnak ISO-NE 413-535-4308 [email protected] Protection System Maintenance & Testing Standard2008-121 Coordinate Interchange Standard Cheryl Mendrala ISO-NE
John Lim Con EdisonRobert Antonishen Ontario Power Generation 905-262-2674 [email protected] Bourassa Hydro Quebec - TransEnergie 819-694-2507 [email protected] Stevenson Constellation Energy 410-787-5260 [email protected] Evans-Mongeon Utility Services 802-552-4022 [email protected] Draxton Constellation Energy Group 410-474-2993 [email protected]
2009-22 Interpretation of COM-002-2 Interpretation Tom Irvine Hydro One Networks 705-792-3004 [email protected] Training (PER) Standard2010-034 Modeling Data (MOD B) Standard2010-045 Demand Data (MOD C) Standard Andrey Oks NPCC2010-05.1 Protection Systems: Phase 1 (Misoperations) Standard Paul Difilippo Hydro One Networks 647-328-7068 [email protected] Phase 2 of Relay Loadability: Generation Standard Steven Hataway Florida Power & Light
Jennifer Dering NYPA 914-287-3179 [email protected] Evans-Mongeon Utility Services 802-552-4022 [email protected] Fedora NPCC 212-840-4909 [email protected] Garg Hydro One Networks 416.345.5420 [email protected] T. Sterling Exelon 630-437-2764 [email protected] Boisvert Hydro Quebec - TransEnergie 514-879-4100 [email protected] Garg Hydro One Networks 416.345.5420 [email protected]
2012-05 ATC Revisions Standard2013-01 Cold Weather Preparedness Standard
Guy Zito NPCC 212-840-1070 [email protected] Kiguel Hydro One Networks [email protected] Bernabeu DominionKenneth Fleischer NextEra EnergyLuis Marti Hydro One Networks
2013-048 Voltage and Reactive Control (VAR) Standard Sharma Kolluri EntergyMark Engels Dominion 804-775-5263 [email protected] Dunn IESO 905-855-6286 [email protected] Esquerre NextEra Energy 561-691-2643 [email protected]
2007-09
2013-03
2013-027
2007-07
2010-14.16
2007-11
N/A
2008-062
2010-17
2010-17
2009-01 Disturbance and Sabotage Reporting Standard
Vegetation Management Standard
Generator Verification Standard
CIP Interpretations Interpretation
Disturbance Monitoring Standard
Balancing Authority Reliability-Based Control, Phase 1: Reserves Standard
Definition of Bulk Electric System
Geomagnetic Disturbance Mitigation Standard
Definition of Bulk Electric System - Rules of Procedure
Standard
Standard
Paragraph 81 Standard
Cyber Security for Order 706 Standard
RSC October 2013 Meeting Item 3.1
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Source = NERC Standard Drafting Team Rosters - September 2013
Change Control: Changes Since August 2013:
1. Project 2008-12, Coordinate Interchange, added to NERC Roster - Chair: Cheryl Mendrala,ISO-NE2. Project 2008-06, Cyber Security for Order 706, John Lim added to NERC Roster3. Project 2010-01, Training (PER), added to NERC Roster4. Project 2010-03, Modeling Data (MOD B), added to NERC Roster5. Project 2010-04, Demand Data (MOD C), added to NERC Roster6. Project 2010-14.1, Balancing Authority Reliability-Based Control, Phase 1: Reserves, Michael Potishnak and Guy Quintin are listed in the NERC Roster but were removed from this list at the June RSC meeting7. Project 2013-02, Paragraph 81, David Kiguel is listed on the NERC Roster but has retired8. Project 2013-04, Voltage and Reactive Control (VAR), added to NERC Roster
RSC October 2013 Meeting Item 3.2
Revised: 9/28/2013Tab Name Last Revised Summary of Changes
NERC RS Exec Tracking Summary 9/28/2013 - Project 2007-09 ― Generator Verification - NOPR issued 9/19/13, comments due 11/25/13- Project 2010-07 ― Generator Requirements at the Transmission Interface - FERC approved 9/19/13- Project 2010-13.2 Phase 2 of Relay Loadability: Generation - PRC-023-2 NERC BOT approved 9/13/13- Project 2012-INT-04 Interpretation of CIP-007 for ITC - Posted for Comment and Ballot thru 9/20/13- Project 2007-06 ― System Protection Coordination - PRC-027-1 - Posted for Comment and Ballot thru 11/1/13- Project 2010-01 ― Support Personnel Training (PER Informal Development Project) - Posted for Comment and Ballot thru 11/11/13- Project 2010-17 ― Definition of Bulk Electric System - Phase 2 - Posted for Comment and Ballot thru 10/28/13- Project 2012-INT-06 CIP-003-3 for Consumers Energy - Industry Approved 9/20/13- Project 2013-03 ― Geomagnetic Disturbance Mitigation - Posted for Comment and Ballot thru 10/18/13- Project 2008-02 ― Undervoltage Load Shedding - SAR posted thru 10/9/13
NERC RSAWs 8/13/2013 - EOP-001-2.1b, Emergency Operations Planning - Revised RSAW Posted 8/9/2013- EOP-005-2, System Restoration from Blackstart Resources - Revised RSAW Posted 7/17/2013- EOP-006-2, System Restoration Coordination - Revised RSAW Posted 7/17/2013- EOP-008-1, Loss of Control Center Functionality - Revised RSAW Posted 6/28/2013- PRC-004-2a, Analysis and Mitigation of Transmission and Generation Protection System Misoperations - Revised RSAW Posted 8/9/2013- PRC-006-1, Automatic Underfrequency Load Shedding - Revised RSAW Posted 6/28/2013
NPCC RRS Tracking Summary 9/16/2013 - Regional Standard Processes Manual - Posted for Comment thru 10/20/13NPCC Doc Tracking Summary 7/16/2012 - B-01: Draft Revised NPCC Guide for the Application of Autorelosing to the Bulk Power System - Posted to Open Process
- A-07 (retired), Revise Critical Component Definition (Glossary of Terms) - retirement date corrected.
NPCC Directory Tracking Summary 8/15/2013 - Directory Development and Revision Manual - Posted for Comment thru 9/29/13NPCC Directory Interpretations 8/13/2013 - NEW Tab for Directory Interpretation trackingQuarterly Filing to NSUARB 8/13/2013 Annotated worksheet to indicate that "Revisions to D#7 and D#12 approved by the Full Members on 7/9/2013. "
Prior RevisionTab Name Last Revised Summary of Changes
Page 1 of 10
Revised: 9/28/2013
Line No. Project No. / TitleNERC
Tracking?PMOS Liaison
NERC Contact Associated Standard SAR Posted?
Posted for Comment?
Posted For Ballot?
Industry Approved?
NERC BOT Approved?
Petitioned for FERC Approval? FERC Approved Comments Project Status
1 Project 2006-02 ― Assess Transmission and Future Needs TPL-001-2Yes 3rd (Thru
3/16/07)Yes 5th (Formal Thru 5/31/11)
Yes (Recirculation Thru 7/22/11) Yes (7/22/11) Yes (8/4/11) Yes (10/19/11)
***DATA REQUEST PUBLISHED - Comments due 8/30/12***
On April 19, 2012 FERC issued Order 762 remanding TPL-002-2b and FERC proposed to remand TPL-001-2. NERC has been directed to revise footnote 'b' in accordance with the directives of Order Nos. 762 and 693.
Pending Regulatory Approval
2 Project 2006-06 ― Reliability CoordinationIRO-002-3, IRO-005-4, IRO-014-2COM-001-2, COM-002-3, IRO-001-3 and IRO-014-2
Yes 3rd "Supp" (Thru 9/3/10)
Yes (Thru 7/6/12)COM-001-2COM-002-3IRO-001-3
Yes (Recirculation Thru 9/17/12)COM-001-2
(Approved 75.01%)Yes (Recirculation
Thru 7/6/12)COM-002-3IRO-001-3
COM-001-2Yes (9/17/12)COM-002-3IRO-001-3
Yes (7/6/12)IRO-002-3IRO-005-4IRO-014-2
Yes (7/25/11)
COM-001-2,COM-002-3
Yes (11/7/12)IRO-001-3
Yes (8/16/12)IRO-002-3IRO-005-4IRO-014-2
Yes (8/4/11)
IRO-001-3IRO-002-3IRO-005-4IRO-014-2
Yes (4/16/13) Pending Regulatory Approval
3 Project 2007-03 ― Real-time Operations TOP-001-2, TOP-002-3, TOP-003-2 and PRC-001-2 PER-001-2Yes 2nd (Thru
9/07/07) Yes (Thru 4/20/12)Yes (Successive
Thru 4/20/12) Update 5/6/12 Update 5/9/12 Yes (4/16/13) Pending Regulatory Approval
4 Project 2007-09 ― Generator Verification Yes N/ASteve
CrutchfieldMOD-024-2, MOD-025-2, MOD-026-1, MOD-027-1, PRC-019-1 and PRC-024-1
Yes 1st (Thru 5/21/07)
PRC-024-1Yes (Thru 1/11/13)
Recirculation Thru 3/27/13: PRC-024-1Recirculation Thru 12/21/12:MOD-025-2, MOD-026-1, MOD-027-1, PRC-019-1
Pending (Recirc Ballot 3/27/13)
Yes (Recirc Ballot 12/21/12)
MOD-025-1, MOD-026-1, MOD-027-
1, and PRC-019-1 -Yes 2/7/13 and
PRC-024-1 - Yes 5/9/13 Yes (5/30/13) NOPR issued on 9/19/13. Comments due 11/25/13. Pending Regulatory Approval x
5 Project 2007-12 ― Frequency Response Yes N/ADarrel
Richardson BAL-003-1Yes 3rd (Thru
3/09/07)Yes 30 day Formal
(thru 11/5/12)Recirculation ballot
thru 12/21/12 Yes (12/21/12) Yes (2/7/13) Yes (3/29/13)
FERC NOPR Issued 7/18/2013 - proposes to approve proposed Reliability Standard BAL-003-1. The Commission also has concerns about certain provisions of the proposed Reliability Standard and, therefore, proposes that NERC submit a report and develop modifications to address the identified concerns. The Commission also proposes to approve four proposed new or revised definitions to the NERC Glossary, NERC’s implementation plan, most proposed violation risk factors and violation severity levels, and NERC’s proposed retirement of currently effective Reliability Standard BAL-003-0.1b. Pending Regulatory Approval
6 Project 2007-17 ― Protection System Maintenance & Testing_RE-INITIATED PRC-005-2Yes 1st (Thru
9/28/11) Yes (Thru 8/27/12)Yes (Recirculation
Thru 10/24/12) Yes (10/24/12) Yes (11/7/12) Yes (2/26/13)
FERC NOPR Issued 7/18/2013 - proposes to approve a revised Reliability Standard, PRC-005-2 – Protection System Maintenance, to supersede four existing Reliability Standards, PRC-005-1.1b (Transmission and Generation Protection System Maintenance and Testing), PRC-008-0 (Underfrequency Load Shedding Equipment Maintenance), PRC-011-0 (Undervoltage Load Shedding Equipment Maintenance) and PRC-017-0 (Special Protection System Maintenance and Testing). In addition, the Commission seeks clarification and comment on three aspects of the proposed Reliability Standard and proposes to modify one violation severity level. Pending Regulatory Approval
7 Project 2008-06 ― Cyber Security ― Order 706 -- CIP Version 5 Standards CIP-002-5 thru CIP-009-5, CIP-010-1 and CIP-011-1 x Yes (Thru 11/5/12)Yes (Recirculation
Thru 11/5/12) Yes (11/5/12) Yes (11/26/12) Yes (1/31/13) Pending Regulatory Approval
8 Project 2008-10 ― Interpretation of CIP-006-1 R1.1 by Progress Energy CIP-006-3d / CIP-006-4d, R1.1 x Yes (thru 11/21/11)Yes (Recirculation
Thru 12/19/11) Yes 12/19/11 Yes (2/9/12) Yes (5/23/12)
3/21/13 FERC issues an order remanding NERC's proposedinterpretation to CIP-006-4, Requirement R1.1. Docket No. RD12-3-000 Pending Regulatory Approval
9Project 2009-19 ― Interpretation of BAL-002-0 R4 and R5 by NWPP Reserve Sharing Group BAL-002-0 R4 and R5 x
Yes - Draft #2 (Thru 9/4/12)
Yes (Recirculation Thru 10/8/12) Yes (10/8/12) Yes (11/7/12) Yes (2/12/13) Pending Regulatory Approval
10 Project 2010-07 ― Generator Requirements at the Transmission Interface FAC-001-1, FAC-003-3, PRC-004-2.1a, PRC-005-1.1bYes 1st (Thru
3/15/10)
Yes (45 Day Formal Thru
4/16/12)Yes (Recirculation
Thru 5/3/12)Yes (12/23/11
and 5/3/12)Yes (2/9/12 and
5/9/12) Yes (7/30/12) Yes (9/19/13)Posted in Federal Register on 9/24/13 - Final Rule effective date 11/25/13. Completed x
11 Project 2010-11 ― TPL Table 1 Order Yes N/AEd
Dobrowolski TPL-001-2a, TPL-001-3, TPL-002-1cYes 1st (Thru
5/26/10)Yes - Formal (Thru
1/11/13)Successive ballot
1/2/13 thru 1/11/13 No (1/11/13) Yes (2/7/13) Yes (2/28/13)
Draft #7 of TPL-001-2a and Draft #6 of TPL-002-1c posted for combined formal comment period and initial ballotOn April 19, 2012 FERC issued Order 762 remanding TPL-002-2b and FERC proposed to remand TPL-001-2. NERC has been directed to revise footnote 'b' in accordance with the directives of Order Nos. 762 and 693. Pending Regulatory Approval
12 Project 2010-INT-01 Interpretation of TOP-006-2 R1.2 and R3 for FMPP TOP-006-3, R1.2 and R3 NAYes - Draft #1 (Thru 7/30/12)
Yes - (Recirculation Thru 9/21/12)
Approved 87.5% 9/21/2012 Yes (11/7/12) Yes (4/5/13) Pending Regulatory Approval
13 Project 2010-INT-05 CIP-002-1 Requirement R3 for Duke Energy CIP-002-4a, R3 x Yes (Thru 3/23/12)Yes (Recirculation
Thru 4/30/12) Yes (4/30/12) Yes (5/9/12) Yes (8/1/12)
3/21/13 FERC issues an order in which it remands the proposed interpretation to Reliability Standard CIP-002-4, Requirement R3. Docket No. RD12-5-000 Pending Regulatory Approval
14 Project 2012-08.1 ― Phase 1 of Glossary Updates: Statutory Definitions YesJennifer Sterling Soo Jin Kim NERC Glossary Of Terms
For Comment (Thru 8/2/12) Yes (Thru 3/22/13)
Yes (Recirculation Thru 4/29/13) Yes (4/29/13) Yes (5/9/13)
Yes (5/10/13)RD13-10-000
Add statutory definitions of Bulk Power System, Reliable Operation, and Reliability Standard to NERC Glossary
15 Project 2013-02 ― Paragraph 81
Retire:• BAL-005-0.2b, R2• CIP-003-3, -4, R1.2• CIP-003-3,-4, R3, R3.1, R3.2, R3.3• CIP-003-3, -4, R4.2• CIP-005-3a, -4a, R2.6• CIP-007-3, -4, R7.3• EOP-005-2 R3.1• FAC-002-1, R2• FAC-008-3 R4, R5• FAC-010-2.1, R5• FAC-011-2, R5• FAC-013-2, R3• INT-007-1, R1.2• IRO-016-1 R2• NUC-001-2, R9.1, 9.1.1, R9.1.2, R9.1.3, R9.1.4• PRC-010-0, R2• PRC-022-1, R2,• VAR-001-2, R5
Draft for Comment (Thru
9/4/12)Yes (Thru 12/10/12)
Yes (Initial Thru 12/10/12)
Recirc Ballot thru 1/17/13 Yes (12/10/12) Yes (2/7/2013) Yes (2/28/2013)
FERC NOPR Published in 6/28/13 Federal RegisterComments are due August 27, 2013.
FERC Issued NOPRDocket #: RM13-8-000 / Date: 6/20/2013Title: NOPR on Electric Reliability Organization Proposal to Retire Requirements in Reliability StandardsSummary: FERC issues a Notice of Proposed Rulemaking (NOPR) proposing to retire 34 requirements within 19 Reliability Standards that are redundant or otherwise unnecessary, and where violations of these requirements pose a lesser risk to the reliability of the Bulk-Power SystemIn addition, the NOPR proposes to withdraw 41 outstanding Commission directives that NERC make modifications to Reliability Standards that have been addressed in some other manner, are redundant with another directive, or provide general guidance as opposed to a specific directive.
Pending Regulatory Approval
NERC Reliability Standards Executive Tracking Summary
Page 2 of 10
Revised: 9/28/2013
Line No. Project No. / TitleNERC
Tracking?PMOS Liaison
NERC Contact Associated Standard SAR Posted?
Posted for Comment?
Posted For Ballot?
Industry Approved?
NERC BOT Approved?
Petitioned for FERC Approval? FERC Approved Comments Project Status
NERC Reliability Standards Executive Tracking Summary
16 Project 2009-22 ― Interpretation of COM-002-2 R2 by the IRC COM-002-2a x2nd (45 day Formal
thru 11/17/11)Yes (Recirculation
Thru 12/23/11) Yes (12/23/11) Yes (2/9/12)
Project 2009-22 (COM-002-2),which applies to real-timeemergency communications, was approved by NERC BOT with an amendment that calls for the prioritization of a revised standard and a best practices memorandum shared with industry. Pending Regulatory Approval
17Project 2010-09 ― Cyber Security Order 706B ― Nuclear Plant Implementation Plan Various CIP Standards
Yes 1st (Thru 3/15/10)
Yes 1st (Thru 3/15/10)
Yes (Recirc Thru 7/2/10) Yes (7/2/10) Yes (8/5/10) Pending Regulatory Approval
18 Project 2010-13.2 Phase 2 of Relay Loadability: Generation YesGary
KruempelScott
Barfield PRC-023-3, PRC-025-1 x
Yes (PRC-023-3 Thru 8/5/13)
Yes (PRC-025-1 Thru 7/19/13)
Yes (PRC-023-3 Final Thru 9/13/13)
Yes (PRC-025-1 Final Thru 8/12/13)
Yes (PRC-023-3 on 9/13/13)
Yes (PRC-025-1 on 8/12/13)
Yes (PRC-023-3 on 9/13/13)
Yes (PRC-025-1 on 8/15/13)
- ".2" refers to Phase 2 of the Projec- 2/15/12 - FERC has granted NERC a one-year extension of time to and including September 30, 2013 to complete the Project pursuant to the Commission’s Order No. 733. [Docket No. RM08-13-001] x
19 Project 2012-INT-05 – Interpretation of CIP-002-3 for OGE CIP-002-3b NAYes (Thru 12/20/12)
Yes (Recirculation Thru 1/23/13) Yes (1/23/13) Yes (2/7/13) Pending Regulatory Approval
20 Project 2009-20 ― Interpretation of BAL-003-0 R2 and R5 by Energy Mark, Inc. BAL-003-0.1b x xYes (Recirc Thru
2/26/10) Yes (2/26/10) Under Development
21Project 2010-14.1 ― Phase 1 of Balancing Authority Reliability-based Control: Reserves Yes
Ken Goldsmith
Darrel Richardson BAL-001, BAL-002, BAL-013 NA Yes (Thru 4/25/13)
Yes (BAL-001-2 Final 7/25/13)
Yes (BAL-002-2 Additional 9/16/13)
Yes (BAL-001-2 on 7/25/13)
As of July 28, 2010 this project has merges Project 2007-18- Reliability-based Controls and is now Project 2010-14 - Balancing Authority Reliability-based Control into a single project Under Development
22 2012-INT-04 Interpretation of CIP-007 for ITC YesSteven Noess CIP-007-3 NA Yes (Thru 3/22/13)
Yes Final (Thru 9/20/13) Yes (9/20/13) x
23 Project 2007-02 ― Operating Personnel Communications Protocols YesBrian
Murphy Joe Krisiak COM-003-1Yes 2nd (Thru
5/2/07) Yes (Thru 7/19/13)Yes (Successive
Thru 7/19/13)
FYI: FAQ Addendum – Additional Question 8: “All Call” protocol resolution postedPosted with RSAW- see RSAW Tab Under Development
24 Project 2007-06 ― System Protection Coordination YesJennifer Sterling Al McMeekin PRC-001-3, PRC-027-1
Yes 1st (Thru 7/10/07)
Yes (PRC-027-1 Thru 11/1/13)
Yes (PRC-027-1 Additional Thru
11/1/13) Under Development x
25Project 2007-17.2 Protection System Maintenance and Testing - Phase 2 (ReclosingRelays) Yes
Gary Kruempel Al McMeekin PRC-005-3
Yes (Thru 5/6/13) Yes (Thru 8/23/13) Yes (Thru 8/23/13)
26 Project 2010-01 ― Support Personnel Training (PER Informal Development Project) Yes Guy ZitoJordan Mallory PER-002, PER-005-2
Yes (Thru 9/3/13)
Yes (Thru 11/11/13) Yes (Thru 11/11/13)
2/15/12 - FERC has granted NERC a two-year extension oftime to and including September 30, 2014 to complete the Project pursuant to the Commission’s Order No. 742. [Docket No. RM09-25-000] Under Development x
27 Project 2010-03 Modeling Data (MOD B) Yes Guy Zito Steve NoessMOD-032-1 and MOD-033-1 (MOD-010, MOD-011, MOD-012, MOD013, MOD-014, MOD-015) x Yes (Thru 9/4/13) Yes (Thru 9/4/13) Under Development
28 Project 2010-04 Demand Data (MOD C) Yes Scott MillerDarrel
RichardsonMOD-031-1 (MOD-016, MOD-017, MOD-018, MOD-019, MOD-020,MOD-021) x Yes (Thru 9/4/13) Yes (Thru 9/4/13) Under Development
29 Project 2010-05.1 ― Protection Systems: Phase 1 (Misoperations) YesJennifer Sterling
Scott Barfield PRC-004-3
Yes 1st (Informal Thru
7/11/11)Yes (Draft #3 Thru
2/20/13)
Yes (Draft #3: Successive Thru
2/20/13) ".1" refers to Phase 1 of the Project
30Project 2010-14.1 ― Phase 1 of Balancing Authority Reliability-based Control: Reserves Yes N/A
Darrel Richardson BAL-012 NA Yes (Thru 4/25/13) Yes (Thru 4/25/13)
As of July 28, 2010 this project has merges Project 2007-18- Reliability-based Controls and is now Project 2010-14 - Balancing Authority Reliability-based Control into a single project This standard will not go forward
31 Project 2010-17 ― Definition of Bulk Electric System - Phase 2 YesJennifer Sterling
Ed Dobrowolski NERC Glossary Of Terms - Revise Definition of Bulk Electric System
For Comment (Thru 2/3/12)
Yes (Thru 10/28/13)
Yes (Additional Thru 10/28/13) Under Development x
32 Project 2012-05 ATC Revisions Order 729 (MOD A) Yes Scott MillerRyan
Stewart MOD-001, MOD-004, MOD-028, MOD-029, MOD-030Yes (Thru 8/26/13 Yes (Thru 8/26/13) Yes (Thru 8/26/13) Under Development
33 Project 2012-INT-06 CIP-003-3 for Consumers Energy YesSteven Noess CIP-003-3 NA
Yes (Formal Thru 3/22/13)
Yes Final (Thru 9/20/13) Yes (9/20/13) x
34 Project 2013-03 Geomagnetic Disturbance Mitigation EOP-010-1Yes (Thru 8/12/13)
Yes (Thru 10/18/13)
Yes (Additional Thru 10/18/13) Under Development x
35 Project 2013-04: Voltage and Reactive Control VAR-001-4, VAR-002-3Yes (Thru
9/3/13) Yes (Thru 9/3/13) Yes (Thru 9/3/13)
36 Project 2007-11 ― Disturbance Monitoring YesGary
Kruempel Barb Nutter PRC-002-1 and PRC-018-1Yes 1st (Thru
4/20/07)
Informal Request for Information (Thru 7/5/13)
Yes (Thru 6/3/13)
This project was brought back to the formal development January, 2013. The drafting team is reviewing and finalizingthe consideration of comments, standard, and other documents in preparation for the next comment period. Under Development
37 Project 2008-12 ― Coordinate Interchange Standards YesCharles Yeung
Steve Crutchfield INT-004-3, INT-006-4, INT-009-2, INT-010-2 and INT-011-1
Yes 1st (Thru 7/31/08)
Yes 1st (Informal Thru 8/23/13) Under Development
38 Project 2009-02 ― Real-time Reliability Monitoring and Analysis Capabilities YesJennifer Sterling
Ed Dobrowolski "New"
Yes 2nd (Thru 2/18/10)
Yes 1st (Informal Thru 4/4/11) Concept White Paper posted for informal comment period Under Development
39Project 2009-03 ― Five-Year Review of Emergency Operations EOP-001, EOP-002, EOP-003, and IRO-001 Yes
Gary Kruempel
Laura Anderson
EOP-001-2b, EOP-002-3, EOP-003-1, EOP-004-2 (P81, RBS), EOP-005-2 (P81, RBS), EOP-006-2 (RBS), EOP-008-1 (RBS), EOP-009-1, IRO-001-5
Yes 1st (Thru 1/15/10) Yes (Thru 9/19/13)
Project initiated as a 5-year review to clarify scope, avoidpotential concurrent revisions to EOP standards (Cold weather SAR) Under Development
40 Project 2010-02 ― Connecting New Facilities to the Grid YesKen
GoldsmithMallory Huggins
FAC-001, FAC-002, FAC-003-3, FAC-008-3, FAC-010-2.1, FAC-0112, FAC-013-2, FAC-014-2 x Yes (Thru 9/16/13)
Two projects (FAC Review, Project 2010-02) wereconsolidated and are being initiated as a 5-year review
41 Project 2010-16 ― Definition of System Operator NERC Glossary Of TermsYes 1st (Thru
12/3/10)Yes 1st (Thru
12/3/10) Under Consideration for Development
42 Project 2012-09 IRO Five-Year Review Yes Ron ParsonSteve
Crutchfield Various IRO standards x Yes (Thru 9/20/13) Five year review Under Development
43 Project 2012-13 NUC Review YesBrian
Murphy Sean Cavote NUC-001Yes (Thru
9/9/13) Yes (Thru 9/9/13) Five year review
44Project 2008-01 ― Voltage and Reactive planning and control (Informal Development Project) Yes
Brian Murphy Soo Jin Kim VAR-001 and VAR-002
Yes 2nd (Thru 3/26/10) Under Development
45 Project 2008-02 ― Undervoltage Load Shedding YesJennifer Sterling
Erika Chanzes PRC-010-0 and PRC-022-1
Yes (Thru 10/9/13) Under Development x
46 Project 2009-05 ― Resource Adequacy Assessments "New"Yes 2nd (Thru
3/30/06) Under Consideration for Development
47 Project 2009-07 ― Reliability of Protection Systems "New"Yes 1st (Thru
2/18/09) Pending prioritization - may be postponed Under Consideration for Development
48 Project 2010-08 ― Functional Model Glossary RevisionsYes 1st (Thru
2/22/10)June 2010 SC meeting - Project deferred until HigherPriority projects are completed Project Deferred
49 Project 2013-01 ― Cold Weather Preparedness YesBrian
Murphy Barb Nutter "TBD"
Draft for Comment (Thru
10/24/12)
50 2012-INT-07 - Interpretation of CIP-005 for AEP YesSteven Noess
This interpretation is being prepared for an initial 30-dayformal comment period.
51 Project 2009-04 ― Phasor Measurement Units Project has not started52 Project 2010-06 ― Results-based Reliability Standards Results-based Reliability Standards Transistion Pla Transistion Plan posted 7/26/10
53Project 2010-14.2 Phase 2 of Balancing Authority Reliability-based Control; TimeError, AGC, and Inadvertent Yes Ron Parson TBD BAL-004, BAL-005-0.1b, BAL-006-2 Under Development
54 Project 2010-INT-03 Interpretation of TOP-002-2a R2, R8, and R19 for FMPP Yes TOP-002-2a, R2, R8 and R19
Standards Committee curtailed work in April 2011 - revivedin January 2012 to see if a Rapid Revision was feasible. Overtaken by filing of TOP standards.
55 Project 2012-01 Equipment Monitoring and Diagnostic Devices FUTURE56 Project 2012-02 Physical Protection FUTURE
57 Project 2012-08.2 ― Phase 2 of Glossary Updates YesJennifer Sterling Soo Jin Kim NERC Glossary Of Terms
Modify existing definition of Transmission Operator andGenerator Operator
58 Project 2012-INT-03 Interpretation of CIP-007 for TECO YesSteven Noess
This interpretation is on hold pending finalization of Project2012-INT-04 (Interpretation of CIP-007 for ITC).
59 Project 2007-07 ― Vegetation Management FAC-003-2Yes 3rd (Thru
7/17/07)Yes 5th (Thru
2/28/11)
Yes 6th (Recirculation Thru
10/13/11) Yes (10/13/11) Yes (11/3/11) Yes (12/21/11) Yes (3/21/13)Posted in Federal Register on 3/28/13 - Standard Enforcement Date 7/1/2014 Completed
60 Project 2008-14 ― Cyber Security Violation Severity Levels CIP family of standardsYes 2nd (Thru
04/20/09)Yes 1st (Thru
04/20/09)Yes (Recirc Thru
7/16/09) Yes (7/16/09) Yes Yes (5/17/10) Yes (9/8/10) Completed
61 Project 2009-01 ― Disturbance and Sabotage Reporting EOP-004-2Yes 1st (Thru
5/21/09) Yes (Thru 9/27/12)Yes (Recirculation
Thru 11/5/12) Yes (11/5/12) Yes (11/7/12) Yes (12/31/12) Yes (6/20/13) EOP-004-2 will be enforceable on January 1, 2014 Completed
Page 3 of 10
Revised: 9/28/2013
Line No. Project No. / TitleNERC
Tracking?PMOS Liaison
NERC Contact Associated Standard SAR Posted?
Posted for Comment?
Posted For Ballot?
Industry Approved?
NERC BOT Approved?
Petitioned for FERC Approval? FERC Approved Comments Project Status
NERC Reliability Standards Executive Tracking Summary
62 Project 2009-24 ― Interpretation of EOP-005-1 R7 by FMPA EOP-005-1, R7 x xYes 1st (Intitial Thru
1/15/10) N/A N/A N/A N/A
In March 2011, FERC approved EOP-005-2, which addressed the issue for which FMPA requested interpretation. The SC curtailed work on this interpretation inApril 2011 and notified FMPA. Curtailed
63 Project 2009-26 ― Interpretation of CIP-004-1 by WECC CIP-004-3a, R2, R3 and R4 x Yes (Thru 3/23/12)Yes (Recirculation
Thru 4/30/12) Yes (4/30/12) Yes (5/9/12) Yes (8/1/12) Yes (12/12/12) Completed
64 Project 2010-17 ― Definition of Bulk Electric System NERC Glossary Of TermsYes 1st (Thru
1/21/11)
- Yes 3rd (Definition Thru 10/10/11)- Yes 2nd (ROP & Tech Principles Thru 10/10/11)
Yes (Recirc Thru 11/21/11) Yes 11/21/11 Yes (1/18/12) Yes (1/25/12) Yes (12/20/12) Completed
65 Project 2010-INT-02 Interpretation of TOP-003-1 R2 for FMPP TOP-003-1, R2 N/A N/A N/A N/A N/A N/A N/A
In May 2011,the SC directed that the requester be notified that a CAN was under development addressing the same issue, and asked the requester to determine whether further processing of the interpretation was necessary. In November 2011 the requester notified NERC staff that no further processing of the interpretation was needed. Completed
66 Project 2011-INT-01 Interpretation of MOD-028 for FPL MOD-028-2Yes 1st (Thru
11/16/11)Yes 1st (Thru
11/16/11)Yes (Recirculation
Thru 12/22/11) Yes (12/22/11) Yes (2/9/12) Yes (8/24/12) Yes (7/18/13)
- The standard shall become effective on the first day of thefirst calendar quarter after Commission approval. - Order effective 60 days after publication in the FEDERAL REGISTER Completed
67 Project 2011-INT-02 - Interpretation of VAR-002 for Constellation VAR-002-2b, R2 x Yes (Thru 6/27/12)Yes (Recirculation
Thru 7/27/12) Yes (7/27/12) Yes (8/16/12) Yes (11/21/12) Yes (4/17/13) "Rapid Revision" Completed
68 Project 2012-INT-02 - Interpretation of TPL-003-0a and TPL-004-0 for SPCS TPL-003-2b and TPL-004-2a NAYes - (Thru
12/5/12)Yes (Recirculation
Thru 1/31/13) Yes (1/31/13) Yes (2/7/13) Yes (4/12/13) Yes (6/20/13)TPL-003-0b and TPL-004-0a became enforceable on June20, 2013 Completed
Acronyms;SAR- Standards Authorization RequestRS- Reliability StandardDT- Drafting TeamSC- NERC Standards CommitteeTBD- To Be DeterminedBOT- NERC Board of Trustee
Page 4 of 10
Revised: 8/13/2013 Further details regarding the individual documents may be found at:http://www.nerc.com/pa/comp/Pages/Reliability-Standard-Audit-Worksheets-(RSAWs).aspx
RSAW# Title Posted for Comment? Comments Posted? RSAW Issued? CommentsBAL-005-0.2b Automatic Generation Control x x 5/20/2013 Revised RSAWs PostedCIP-001-2a Sabotage Reporting x x 10/13/2012COM-002-2a Communication and Coordination x Yes (4/27/12) 11/14/2012COM-003-1 Operating Personnel Communications Protocols Yes (Thru 4/5/13)EOP-001-2.1b Emergency Operations Planning x x 8/9/2013 Revised RSAWs Posted xEOP-002-3.1 Capacity and Energy Emergencies x x 5/20/2013 Revised RSAWs PostedEOP-003-2 Load Shedding Plans x x 10/13/2012EOP-005-2 System Restoration from Blackstart Resources x x 7/17/2013 Revised RSAWs Posted xEOP-006-2 System Restoration Coordination x x 7/17/2013 Revised RSAWs Posted xEOP-008-1 Loss of Control Center Functionality x x 6/28/2013 Revised RSAWs Posted xFAC-008-3 Facility Ratings x x 11/20/2012
FAC-013-2Assessment of Transfer Capability for the Near-Term Transmission Planning Horizon x x 10/13/2012
IRO-005-3.1a Reliability Coordination - Current-Day Operations x x 5/20/2013 Revised RSAWs Posted
IRO-014-1Procedures, Processes, or Plans to Support Coordination Between Reliability Coordinators x x 10/13/2012
PER-001-0.2 Operating Personnel Responsibility and Authority x x 5/20/2013 Revised RSAWs PostedPER-003-1 Operating Personnel Credentials x x 1/23/2013PER-005-1 System Personnel Training Yes (Thru 4/30/12) Yes (4/27/12) 8/10/2012
PRC-004-2aAnalysis and Mitigation of Transmission and Generation Protection System Misoperations x x 8/9/2013 Revised RSAWs Posted x
PRC-005-1b Transmission and Generation Protection System Maintenance and Testing x x 4/2/2013PRC-006-1 Automatic Underfrequency Load Shedding x x 6/28/2013 Revised RSAWs Posted xPRC-023-2 Transmission Relay Loadability x x 11/15/2012PRC-025-1 Generator Relay Loadability Yes (Thru 3/11/13)TOP-001-1a Reliability Responsibilities and Authorities x x 5/20/2013 Revised RSAWs PostedTOP-002-2.1b Normal Operations Planning x x 5/20/2013 Revised RSAWs Posted
TPL-002-0bSystem Performance Following Loss of a Single Bulk Electric System Element (Category B) x x 5/20/2013 Revised RSAWs Posted
VAR-002-2b Generator Operation for Maintaining Network Voltage Schedules x x 6/7/2013 Revised RSAWs Posted
NERC Reliability Standard Audit Worksheet (RSAW) Executive Tracking Summary
Page 5 of 10
Revised: 9/16/2013 Further details regarding the individual documents may be found at: http://www.npcc.org/regStandards/UnderDev.aspx
Line No. Regional Standard ID Regional Reliability Standard TitleRSAR
Posted?Posted for Comment?
Posted For Ballot?
Industry Approved?
NPCC BOD Approved?
NERC BOT Approved?
Petitioned for FERC Approval? FERC Approved Comments Project Status
1 BPS-501-NPCC-01 Classification of Bulk Power System Elements (Withdrawn by RSC 8/07/09)Yes (Thru
2/4/08) NA NA NA NA NA NA NA Withdrawn by RSC 8/07/09 Withdrawn
2 PRC-002-NPCC-01 Disturbance MonitoringYes (Thru 9/10/08)
Yes (Thru 10/24/09) Yes (Thru 1/6/10) Yes (1/6/10) Yes (1/9/10) Yes (11/4/10) Yes (5/31/11) Yes (10/20/11) 10/24/11 - Approved Standard posted publicly Completed
3 PRC-006-NPCC-01 Automatic Underfrequency Load Shedding ProgramYes (Thru 8/25/08) Yes (Thru 11/2/11)
Yes (Pre-ballotThru 11/2/11) Yes (11/18/11) Yes (11/30/11) Yes (2/9/12) Yes (5/4/12) Yes (2/21/13) Completed
4 PRC-006-NPCC-02
- Regional Standard Authorization Request (RSAR) has been submitted and approved- Drafting Team Nomination period ended March 25, 2013- Draft Team kick-off conference call was Monday April 8, 2013 Under Development
5 PRC-002-NPCC-01, Interpretation R1.1 x x xYes (TFSP 10/19/12) N/A N/A N/A N/A
Posted on the NPCC website under "Regional Standards General" on 6/24/13 Completed
6PRC-002-NPCC-01, Interpretation R1.2.2 x x x
Yes (TFSP 4/8/13) N/A N/A N/A N/A
Posted on the NPCC website under "Regional Standards General" on 6/24/13 Completed
7PRC-002-NPCC-01, Interpretation R4, R5, and R6 x x x
Yes (TFSP 5/16/13) N/A N/A N/A N/A
Posted on the NPCC website under "Regional Standards General" on 6/24/13 Completed
8 BAL-002-NPCC-01 Regional Reserve SharingYes (Thru 11/2/10)
Yes (Thru 12/16/11) Yes (Thru 1/6/10) Nomination Form posted - nominations due by 11/10/11 Under Development
9 PRC-012-NPCC-01 Special Protection SystemsYes (thru 8/18/08) On Hold
10 Regional Standard Processes Manual Regional Standard Process Manual (RSPM) N/AYes (Thru 10/20/13) x
Acronyms;RSAR- Regional Standards Authorization RequestRRS- Regional Reliability StandardDT- Drafting TeamSC - NERC Standards CommitteeTBD- To Be DeterminedBOD- NPCC Board of DirectorsBOT- NERC Board of Trustee
NPCC Regional Reliability Standards Executive Tracking Summary
Page 6 of 10
Revised: 7/16/2012 Further details regarding the individual documents may be found at: https://www.npcc.org/Standards/SitePages/NonStandardsList.aspx
Line No. Type Document DescriptionEffective
Date Comments Status1 Criteria A-01 Criteria for Review and Approval of Documents2 Criteria A-10 Classification of BPS Elements3 Criteria A-15 Disturbance Monitoring Equipment Criteria 4 Guideline B-01 NPCC Guide for the Application of Autoreclosing to the Bulk Power System5 Guideline B-12 Guidelines for On-Line Computer System Performance During Disturbances6 Guideline B-25 Guide to Time Suynchronization7 Guideline B-26 Guide for Application of Disturbance Recording Equipement 8 Guideline B-27 Regional Critical Asset Identification Methodology9 Guideline B-28 Guide for Generator Sequence of Events Monitoring
10 Procedure C-00 Listing of NPCC Documents by Type
11 Procedure C-01NPCC Emergency Preparedness Conference Call Procedures - NPCC Security Conference Call Procedures
12 Procedure C-05 Monitoring Procedures for Emergency Operation Criteria13 Procedure C-07 Monitoring Procedures for the Guide for Rating Generating Capability
14 Procedure C-15 Procedures for Solar Magnetic Disturbances Which Affect Electric Power Systems15 Procedure C-17 Procedures for Monitoring and Reporting Critical Operating Tool Failures
16 Procedure C-21Monitoring Procedures for Conformance with Normal and Emergency Transfer Limits
17 Procedure C-25 Procedure to Collect Power System Event Data18 Procedure C-29 Procedures for System Modeling:Data Requirements and Facility Ratings
19 Procedure C-30Procedure for Task Force on System Protection Review of Disturbances and Protection Misoperations
20 Procedure C-33 Procedure for Analysis and Classification of Dynamic Control Systems21 Procedure C-36 Procedures for Communications During Emergencies22 Procedure C-39 Procedure to Collect Major Disturbance Event Data23 Procedure C-42 Procedure for Reporting and Reviewing System Disturbances24 Procedure C-43 NPCC Operational Review for the Integration of New facilities25 Procedure C-44 NPCC Regional Methodology and Procedures for Forecasting TTC and ATC26 Procedure C-45 Procedure for Analysis and Reporting of Protection System Misoperations
27 ProcedureCost Effectiveness Analysis Procedure - CEAP
28 Glossary NPCC Glossary of Terms
Acronyms;
NPCC Document Open Process Executive Tracking Summary
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Revised: 8/15/2013 Further details regarding the individual documents may be found at: https://www.npcc.org/Standards/SitePages/NonStandardsList.aspx
Line No. DocumentDeveloped
From Title of Directory PhaseTask Force
ReviewPosted Open
Process?RCC
Approval?
Full Membership
Ballot? Comments Status
1 Directory #1 Criteria A-2 Design and Operation of the Bulk Power SystemTFCP(CP11)
and TFCO (CO7)
CP11 and CO7 Collaborative review of the Directory #1 Planning and Operating Criteria.
2 Directory #2 Criteria A-3 Emergency Operations TFCO Phase 2 reformatting pending TFCO resources.
3 Directory #3 Criteria A-4 Maintenance Criteria for Bulk Power System Protection TFSPTFSP to identify differences/gaps between Directory #3 and draft revised PRC-005 and evaluate impact of retiring Directory #3 – pending FERC approval of PRC -005-2
4 Directory #4 Criteria A-5 Bulk Power System Protection Criteria TFSP Open Process posting expected in 2013. TFSP currently reviewing D#4.
5 Directory #5 Criteria A-6 Reserve TFCO Revisions to Version 0 of Directory #5 approved by the NPCC Full Members in October 2012.
6 Directory #6 Regional Reserve Sharing 1/2/1900 Passed 04/09/2012
Directory #6 approved by the NPCC Full Members in Phase 2 format in April 2012.
7 Directory #7 Criteria A-11 Special Protection Systems TFSP Passed 7/9/2013 TFSP Revisions.
8 Directory #8 Criteria A-12 System Restoration TFCO TFCO working group CO11 reviewing initial Phase 2 draft of Directory #8.
9 Directory #9 Criteria A-13 Verification of Generator Gross and Net Real Power Capability 1/2/1900 TFCO Passed 12/28/11 Directory#9 Phase 2 reformatting complete December 2011.
10 Directory #10 Criteria A-14 Verification of Generator Gross and Net Reactive Power Capability 1/2/1900 TFCO Passed 12/28/11 Directory#10 Phase 2 reformatting complete December 2011.
11 Directory #11
12 Directory #12 Under frequency Load Shedding Program Requirements TFSS Passed 7/9/2013 TFSS Revisions Directory#12 will be retired once PRC-006-NPCC-1 is fully implemented.
13 Manual Directory Development and Revision Manual Yes (Posted thru 9/29/13) Open Process x
NPCC Directory Executive Tracking Summary
Page 8 of 10
Revised: 8/13/2013 Further details regarding the individual documents may be found at: https://www.npcc.org/Standards/Directory%20Interpretations/Forms/Public%20List.aspx
Line No. Document Title of Directory Date FinalTask Force
ReviewPosted Open
Process?RCC
Approval?
Full Membership
Ballot? Comments Status
1 Directory #8 Interpretation System Restoration 6/18/2012 TFCO N/A N/A Interpretation on behalf of the NYSRC Complete x
2 Directory#3 Interpretation Maintenance Criteria for Bulk Power System Protection 8/28/2012 TFSP N/A N/A Interpretation on behalf of Bangor Hydro Complete x
3 Directory #3 Interpretation Maintenance Criteria for Bulk Power System Protection 12/14/2012 TFSP N/A N/A Interpretation on behalf of Acumen
Engineered Solutions Complete x
4 Directory #3 Interpretation Maintenance Criteria for Bulk Power System Protection 12/14/2012 TFSP N/A N/A Interpretation on behalf of Con Ed Complete x
5 Directory#3 Interpretation Maintenance Criteria for Bulk Power System Protection TFSP N/A N/A Interpretation on behalf of IESO Pending TFSP Review x
NPCC Directory Interpretations
Page 9 of 10
Revised: 8/13/2013
Line No. Filing Period Filing Due Filing Submitted Comments
1 October 1 to December 31, 2012 3/1/2013 3/1/2013This filing is NPCC’s initial quarterly filing covering the October 1 to December 31, 2012 period and covers the changes to the NPCC Criteria as a result of voting by the Full Members of NPCC.
2 January 1 to March 31, 2013 6/1/2013 N/A No changes were made during the refeenced period which required filing.3 April 1 to June 30, 2013 9/1/2013 No changes were made during the refeenced period which required filing.4 July 1 to September 30, 2013 12/1/2013 Revisions to D#7 and D#12 approved by the Full Members on 7/9/2013. 5 October 1 to December 31, 2013 3/1/2014
Quarterly Application to the Nova Scotia Utility and Review Board (NSUARB) for Approval of NPCC Regional Reliability Criteria
Page 10 of 10
RSC October 2013 Meeting Item 4.0 RSC Meeting #13-5, Agenda Item 4.0 Open Action Items
Page 1 of 1
Item Description Owner Due Status 4.1 Coordination with the
Compliance Committee to develop Joint Activity Action List
Greg Campoli
RSC Meeting Ongoing
4.2 New York Adoption of More Stringent/Specific NPCC Criteria - determine more stringent criteria and submit filing
Michael Lombardi and Gerry Dunbar
12/31/13 Ongoing
4.3 PRC-005 Guidance - Investigate maintenance cycles that are more stringent than those in the standard
Ron Falsetti 10/9/13 Target completion by next RSC meeting on 10/9/13
13.3-2 Kathleen Goodman agreed to identify and present proposed improvements to the NPCC ETS for consideration by the RSC.
Kathleen Goodman
13-3.8 NPCC Standards Staff to develop outreach proposal.
NPCC Standards Staff
13-4.1 NPCC to notify Ontario of any new or revised NPCC criteria when approved by the NPCC BOT. Incorporate this request into the process for filing completed directories.
Gerry Dunbar
New
13-4.2 Post the proposed revision of the RSPM for a 45-day comment period
Michael Lombardi
Completed – RSPM posted for a 45-day comment period through 10/20/13
13-4.3 Post clarification if the applicability of PRC-006-NPCC-1 is dependent on generator underfrequency trip relay location
Gerry Dunbar
Completed – clarification was reviewed with task force and posted.
13-4.4 Provide feedback to the SCPS on the quality issues that are being found in the standards recently posted for comment and/or ballot
Guy Zito Completed – discussed at SCPS meeting held on 9/18/13
Northeast Power Coordinating Council, Inc.
Regional Standards Processes Manual (RSPM)
Adopted by FERC: XXXX XX, 20XX
Approved by NERC Board of Trustees: XXXX XX, 20XX
Approved by NPCC Board of Directors: XXXX XX, 20XX
DRAFT FOR REVIEW & COMMENT Last Updated 8/13/13
Note to reviewers: Links to NERC website and process flow charts will be finalized for the final review.
RSC October 2013 Meeting Item 5.2a
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Revision History
Version NPCC Board Of
Directors Approval NERC Board Of
Trustees Approval FERC Approval 0 9/19/07 10/23/07 3/21/08 1 xx/xx/xx xx/xx/xx xx/xx/xx
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NPCC REGIONAL RELIABILITY STANDARDS PROCESS MANUAL
TABLE OF CONTENTS I. EXECUTIVE SUMMARY ................................................................................................. 3 II. INTRODUCTION............................................................................................................ 4
PURPOSE ............................................................................................................................................... 4 BACKGROUND .................................................................................................................................... 4
III. REGIONAL STANDARD CHARACTERISTICS AND ELEMENTS ................... 5 1. CHARACTERISTIC ATTRIBUTES ........................................................................................ 5 2. ELEMENTS OF A REGIONAL STANDARD ........................................................................ 6
TYPES OF RELIABILITY REQUIREMENTS ................................................................................................................ 6 ELEMENTS OF A REGIONAL STANDARD ................................................................................................................. 7
IV. REGIONAL STANDARDS DEVELOPMENT PROCESS ...................................... 9 1. ROLES IN THE NPCC REGIONAL STANDARD PROCESS ............................................ 9
NOMINATION, REVISION, CLARIFICATION, OR RETIREMENT OF A STANDARD: ..................................................... 9 PROCESS ROLES AND RESPONSIBILITIES .............................................................................................................. 9
2. STANDARD DEVELOPMENT PROCESS STEPS ............................................................. 11 STEP 2.1: REGIONAL STANDARDS AUTHORIZATION REQUEST TO DEVELOP, MODIFY OR RETIRE ..................... 11 STEP 2.2: FORMATION OF DRAFTING TEAM FOR NEW OR MODIFIED STANDARD .............................................. 13 STEP 2.3: DEVELOPMENT OF A REGIONAL STANDARD AND ASSOCIATED DOCUMENTS ..................................... 14 STEP 2.4: POSTING FOR COMMENT PERIOD AND RESOLUTION OF COMMENTS ................................................. 15 STEP 2.5: POSTING FOR BALLOT PERIOD IN THE OPEN PROCESS ..................................................................... 16 STEP 2.6: NPCC BOARD OF DIRECTORS APPROVAL ......................................................................................... 18 STEP 2.7: NERC BOARD OF TRUSTEES SUBMITTAL ........................................................................................... 18 STEP 2.8: IMPLEMENTATION OF A NPCC REGIONAL STANDARD ....................................................................... 19
3. STANDARD CLARIFICATION PROCESS STEPS ............................................................ 19 STEP 3.1: REGIONAL STANDARDS REQUEST FOR CLARIFICATION (RFC) .......................................................... 19 STEP 3.2: REVIEW AND VALIDATION OF REQUEST FOR CLARIFICATION (RFC) ................................................. 20 STEP 3.3: NPCC REGIONAL STANDARDS COMMITTEE (RSC) ACTIONS ............................................................ 20 STEP 3.4: FORMATION OF DRAFTING TEAM FOR RESPONSE TO RFC ................................................................ 21 STEP 3.5: DEVELOPMENT OF RESPONSE TO RFC .............................................................................................. 21 STEP 3.6: POSTING RFC FOR COMMENT PERIOD AND RESOLUTION OF COMMENTS ........................................ 21 STEP 3.7: REGIONAL STANDARDS COMMITTEE APPROVAL OF RFC .................................................................. 22 STEP 3.8: NPCC BOARD OF DIRECTORS APPROVAL OF RFC ........................................................................... 22
4. CURTAILMENT OF REGIONAL STANDARD DEVELOPMENT ................................ 23 5. WITHDRAWAL OF A REGIONAL STANDARD PENDING APPROVAL ................... 23 6. RETIREMENT OF AN APPROVED NPCC REGIONAL STANDARD.......................... 23 7. APPROVAL OF PROCESS WAIVER ................................................................................... 23 8. PROCESS FOR CORRECTING ERRATA ........................................................................... 24 9. APPEALS ..................................................................................................................................... 25
LEVEL 1 APPEAL ................................................................................................................................................. 25 LEVEL 2 APPEAL ................................................................................................................................................. 25
APPENDIX A: RSAR COMPLETION GUIDELINES ......................................................... 1 APPENDIX B: SELECTION OF DRAFTING TEAM MEMBERS ................................... 1 APPENDIX C: MAINTENANCE OF REGIONAL STANDARDS AND PROCESS ...... 1
MAINTENANCE OF REGIONAL STANDARDS ........................................................................................................... 1 MAINTENANCE OF THE REGIONAL STANDARDS PROCESS ..................................................................................... 1
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I. EXECUTIVE SUMMARY The NPCC Bylaws state “NPCC shall develop a Regional Reliability Standards Development Procedure that provides the design-basis approach to a consensus building process by which NPCC may develop Regional Reliability Standards and Regional Variances to be proposed to the ERO for adoption, under delegated authority by the FERC and the Canadian Provincial regulatory and/or governmental authorities.”
The NPCC Regional Reliability Standards Development Procedure was originally adopted by the NPCC Board of Directors on September 19, 2007. The NPCC Reliability Standards Staff in concert with the NPCC Regional Standards Committee (RSC) has completed a revision to the NPCC Regional Reliability Standards Process Manual to incorporate process improvements, provide greater clarity and reflect the new NPCC Cost Effectiveness Analysis Procedure (CEAP).
Key changes addressed in this revision include:
• Replacing interpretation with clarification and Eexpanding the interpretation Clarification Section narrative into process steps and including an associated flowchart
• Creating separate sections for: 1) Withdrawal Of A Regional Standard Pending Approval; 2) Retirement Of An Approved NPCC Regional Standard; and 3) Approval Of Process Waiver; 4) Process For Correcting Errata
• Recognizing the new NPCC Cost Effectiveness Analysis Procedure (CEAP)
• Identifying the Reliability Standard Audit Worksheet (RSAW) as a companion document to a regional standard that needs to be collaboratively developed by the drafting team and NPCC Compliance Staff
• Creating three new appendices: 1) Appendix A: Regional Standard Authorization Request (RSAR) Completion Guidelines and Form; 2) Appendix B: Selection Of drafting team Members and Nomination Form; and 3) Appendix C: Maintenance Of Regional Standards and Process
In addressing areas for improvement in the NPCC Regional Reliability Standards Development Procedure, recent improvements made to the NERC Standards Process Manual (e.g., Standards Process Input Group (SPIG) recommendations) as well as the manuals of other Regional Entities were benchmarked to identify best practices for inclusion in this manual.
The process improvements and clarity captured in this revision to the NPCC Regional Reliability Standards Development Procedure, will result in a more timely and efficient manner to address the development of regional standards to ensure the reliability of the Bulk Electric System within the NPCC geographical area.
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II. INTRODUCTION PURPOSE
This manual defines the characteristics of a Northeast Power Coordinating Council, Inc. (NPCC) regional Reliability Standard (hereinafter referred to as “regional standard”) and establishes the process by which NPCC regional standards are developed, approved, revised, formally interpreted and retired. The NPCC regional standards process is a stakeholder process that is approved by the NPCC members to ensure a transparent standard development process that is “open, fair, and inclusive.”
NPCC regional standards address the reliability of the international and interconnected Bulk Electric System in Northeast North America. NPCC regional standards shall enable or support one or more NERC/ERO reliability principles1 and will, in all cases, not be inconsistent with or less stringent than any requirements of the North American Electric Reliability Council/Electric Reliability Organization (NERC/ERO) continent-wide Reliability Standards.
The development of NPCC regional standards is performed according to the following principles using the process contained in this manual:
• Developed in a fair and open process that provides an opportunity for all interested parties to participate;
• Does not have an adverse impact on commerce that is not necessary for reliability;
• Provides a level of Bulk Electric System reliability that is adequate to protect public health, safety, welfare, and national security and would not have a significant adverse impact on reliability; and
• Based on a justifiable difference between Regions or between sub-Regions within the Regional geographic area.
Following industry approval, NPCC regional standards process and NPCC regional standards require approval by the NPCC Board of Directors, NERC as the Electric Reliability Organization (ERO) and the applicable regulatory authorities in the United States (FERC) and Canada.
BACKGROUND
Northeast Power Coordinating Council, Inc. (NPCC) is responsible for promoting and improving the reliability of the international, interconnected Bulk Electric System in Northeastern North America. NPCC carries out its mission through (i) the development of regional standards and compliance assessment and enforcement of continent-wide and regional standards, coordination of system planning, design and operations, and assessment of reliability, (collectively, “Regional Entity activities”), and (ii) the establishment of regionally-specific criteria, and monitoring and enforcement of compliance with such criteria (collectively, “criteria services activities”).
The Energy Policy Act (EPA) of 2005 (Section 1211) amended the Federal Power Act (FPA) by adding Section 215, Electric Reliability. Specifically regarding standards development and pursuant with Section 215(e)(4) of the FPA, NPCC as a Regional Entity with delegated authority from NERC may propose regional standards to NERC for eventual enforcement within the NPCC region.
1 Available on the NERC website: Reliability Principles
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As a condition of NPCC membership, NPCC General and Full Members2 agree to adhere to NERC Reliability Standards. NERC Reliability Standards are comprised of both continent-wide and regional standards. The NPCC regional standards apply only to that part of the Eastern Interconnection within the NPCC geographical area.
III. REGIONAL STANDARD CHARACTERISTICS AND ELEMENTS 1. CHARACTERISTIC ATTRIBUTES
The NPCC regional standards development process has the following key characteristics:
• Fair due process — The NPCC regional standards development process provides for reasonable notice and opportunity for public comment. At a minimum, the procedure shall include public notice of the intent to develop a standard, a public comment period on the proposed standard, due consideration of those public comments, and a ballot of interested stakeholders. Upon approval by the NPCC Members, the NPCC Board of Directors then votes to approve submittal of the regional standard to NERC for ERO approval, followed by submission to FERC and Canadian Authorities for their approvals.
• Openness — Participation in the NPCC regional standards development process is open to all persons and organizations that are directly and materially affected by the reliability of the NPCC’s Bulk Electric System. There is no undue financial burden to participation. Participation shall not be conditioned upon membership in the ERO, NPCC or any organization, and shall not be unreasonably restricted on the basis of technical qualifications or other such requirements.
• Inclusive — Any entity (person, organization, company, government agency, individual, etc.) with a direct and material interest in the reliability of NPCC’s Bulk Electric System has the right to participate by: (a) expressing an opinion and its basis; (b) having their position considered, and (c) having the right to appeal a response through an established appeal process.
• Balanced — The NPCC regional standards development process strives to have an appropriate balance of interest and shall not be dominated by any two interest categories and no single interest category shall be able to defeat a matter. Pursuant with the NPCC By-Laws3 there are seven (7) stakeholder voting sectors and the votes for each sector are weighted to achieve an appropriate balance.
• Transparent — All actions material to the development of NPCC regional standards are transparent and information regarding the progress of a standard’s development action is made available to the public through postings on the NPCC website as well as through E-mail lists.
• Without undue delay — The NPCC regional standards development process shall be performed within a reasonable time.
In as much as NPCC is one of six Regional Entities within the Eastern Interconnection of North America, there will be no presumption of validity by the ERO for any NPCC regional standard.
2 As defined in the NPCC By-Laws – available on the NPCC website 3 NPCC By-Laws are available on the NPCC website
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In order to receive the approval of the ERO, the NPCC regional standards development process must also achieve the following objectives:
• No Adverse Impact on Reliability of the Interconnection — A NPCC regional standard provides a level of Bulk Electric System reliability that is necessary and adequate to protect public health, safety, welfare, and North American security and will not have an adverse impact on the reliability of the Interconnection or other Regions within the Interconnection.
• Justifiable Difference — A NPCC regional standard addresses a justifiable difference within the NPCC geographical area that results from a physical difference4 or operating difference in the Northeast’s Bulk Electric System. Although a justifiable difference allows for a unique regional standard, a NPCC regional standard shall be no less stringent than a continent-wide standard.
• Uniformity — To the extent possible, the NPCC regional standards provides uniformity with Reliability Standards across the interconnected Bulk Electric System of North America.
• No Undue Adverse Impact on Commerce — A NPCC regional standard will not cause any undue adverse impact on business activities that are not necessary for reliability of the Region and its interconnected Regions. All regional standards shall be consistent with NERC’s market principles5.
2. ELEMENTS OF A REGIONAL STANDARD
To ensure uniformity of regional standards and avoid inconsistency with NERC continent-wide standards, a NPCC regional standard shall be consistent with the elements identified in this section of the procedure. These elements are intended to apply a systematic discipline in the development and revision of regional standards. The application of a systematic discipline is necessary for achieving regional standards that are measurable, enforceable, and consistent as well as results oriented6, i.e.:
• Performance-based,
• Risk-based, and
• Capability-based. TYPES OF RELIABILITY REQUIREMENTS
The drafting team (DT) should strive to achieve a portfolio of performance, risk, and capability-based mandatory reliability requirements that support an effective defense-in-depth strategy. Each requirement should identify a clear and measurable expected outcome, such as: a) a stated level of reliability performance, b) a reduction in a specified reliability risk, or c) a necessary competency.
4 The interpretation meaning of the phrase “physical difference” will be consistent with FERC’s Order, issued
September 22, 2004, Granting Request For Clarification regarding Docket No. PL04-5-000, Policy Statement on Matters Related to Bulk Power System Reliability.
5 Available on the NERC website: www.nerc.com 6 Results-based Standards see http:www.nerc.com/filez/standards/Project2010-06_Results-
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a) Performance-based - defines a specific reliability objective or outcome that has a direct, observable effect on the reliability of the Bulk Electric System, i.e. an effect that can be measured using power system data or trends.
b) Risk-based - defines actions of entities that reduce a stated risk to the reliability of the Bulk Electric System and can be measured by evaluating a particular product or outcome resulting from the required actions.
c) Capability-based - defines capabilities needed to perform reliability functions and can be measured by demonstrating that the capability exists as required.
Each regional standard shall enable or support one or more of the reliability principles 7 as identified in the most recent set posted on the NERC website. Each regional standard shall also be consistent with all of the reliability principles. The intent of the set of NPCC regional standards is to deliver an Adequate Level of Reliability8 as defined by NERC.
Recognizing that Bulk Electric System reliability and electricity markets are inseparable and mutually interdependent, all regional standards shall be consistent with the most recent set of Market Principles9 as posted on the NERC website. Consideration of the Market Principles is intended to ensure that regional standards are written such that they achieve their reliability objective without placing undue restrictions or causing adverse impacts on competitive electricity markets.
ELEMENTS OF A REGIONAL STANDARD
A regional standard includes several components designed to work collectively to identify what entities must do to meet their reliability-related obligations as an owner, operator or user of the Bulk Electric System. The components of a NPCC regional standard identified below are based on the NERC Standard Processes Manual (SPM) that was approved by the NERC Board of Trustees at its February 2013 meeting. Future revisions of the NERC SPM will be used at the time of development of a NPCC regional standard if different from the elements listed below.
The only mandatory and enforceable components of a regional standard are the: (1) Applicability, (2) Requirements, and (3) the Effective Dates. The additional components are included in the regional standard for informational purposes, to establish the relevant scope and technical paradigm, and to provide guidance to functional entities concerning how compliance will be assessed by the Compliance Enforcement Authority.
The components of a regional standard may include the following: Title: A brief, descriptive phrase identifying the topic of the regional standard.
Number: A unique identification number assigned in accordance with a published classification system to facilitate tracking and reference to the regional standards.
Purpose: The reliability outcome achieved through compliance with the requirements of the regional standard.
Applicability: Identifies which entities are assigned reliability requirements; i.e., the specific functional entities and facilities to which the regional standard applies.
7 Available on the NERC website: Reliability Principles 8 Available on the NERC website: Adequate Level of Reliability 9 Available on the NERC website: Market Principles
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Effective Dates: Identification of the date or pre-conditions determining when each Requirement becomes effective in each jurisdiction.
Requirement: An explicit statement that identifies the functional entity responsible, the action or outcome that must be achieved, any conditions achieving the action or outcome, and the reliability-related benefit of the action or outcome. Each requirement shall be a statement for which compliance is mandatory.
Compliance Elements: Elements to aid in the administration of compliance monitoring and enforcement responsibilities.
Measure: Provides identification of the evidence or types of evidence that may demonstrate compliance with the associated requirement.
Violation Risk Factors and Violation Severity Levels:
Violation risk factors (VRFs) and violation severity levels (VSLs) are used as factors when determining the size of a penalty or sanction associated with the violation of a requirement in an approved Reliability Standard. Each requirement in each Reliability Standard has an associated VRF and a set of VSLs. VRFs and VSLs are developed by the drafting team, working with NPCC Standards Staff and Compliance Staff, at the same time as the associated Reliability Standard, but are not part of the Reliability Standard. The Board of Directors is responsible for approving VRFs and VSLs.
• Violation Risk Factors VRFs identify the potential reliability significance of noncompliance with each requirement. Each requirement is assigned a VRF in accordance with the latest approved set of VRF criteria.
• Violation Severity Levels VSLs define the degree to which compliance with a requirement was not achieved. Each requirement shall 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. Each requirement is assigned one or more VSLs in accordance with the latest approved set of VSL criteria.
Version History: The version history is provided for informational purposes and lists information regarding prior versions of the regional standard.
Variance: As applied to a NPCC regional standard is a Requirement (to be applied in the place of the NPCC region-wide Requirement) that is applicable to a specific geographic area or to a specific set of Registered Entities.
Compliance Enforcement Authority (CEA):
The entity that is responsible for assessing performance or outcomes to determine if an entity is compliant with the associated regional standard. The Compliance Enforcement Authority will be NERC or the Regional Entity in their respective roles of monitoring and enforcing compliance with the ERO regional standards.
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Reliability Standard Audit Worksheets (RSAWs)10
Reliability Standard Audit Worksheets (RSAWs) are developed as companion documents to regional and continent-wide Reliability Standards to facilitate the CEA assessment of a registered entity’s compliance with a standard.
Informational Elements: Elements to aid in the implementation of the regional standard. Application Guidelines:
Guidelines or reference documents to support the implementation of the associated regional standard.
Procedures: Procedures to support implementation of the associated regional standard.
IV. REGIONAL STANDARDS DEVELOPMENT PROCESS 1. ROLES IN THE NPCC REGIONAL STANDARD PROCESS
NOMINATION, REVISION, INTERPRETATIONCLARIFICATION, OR RETIREMENT OF A STANDARD:
Any member of NPCC or group within the NPCC region shall be allowed to request that a NPCC regional standard be developed, modified, interpreted, or retired. Additionally, any person (organization, company, government agency, individual, etc.) who is directly and materially affected by the reliability of the NPCC Bulk Electric System shall be allowed to request that a NPCC regional standard be developed, modified, interpreted, or retired. The following section identifies the process roles in the NPCC regional standards process. Refer to Step 2 STANDARD DEVELOPMENT PROCESS STEPSSTANDARD DEVELOPMENT PROCESS STEPS and FIGURE 1: FLOWCHART OF REGIONAL STANDARDS DEVELOPMENT PROCESSFIGURE 1: FLOWCHART OF REGIONAL STANDARDS DEVELOPMENT PROCESS for the regional standards development process steps and associated flowchart.
PROCESS ROLES AND RESPONSIBILITIES
BOARD OF DIRECTORS The NPCC Board of Directors (Board) shall consider for adoption regional standards, definitions, variances and interpretations clarifications and associated implementation plans that have been processed according to the processes identified in this manual. Once the Board adopts a regional standard, definition, variance or clarificationinterpretation, the Board shall direct NPCC Standards Staff to submit the document(s) for approval to the NERC Board of Trustees.
COMPLIANCE COMMITTEE (CC) The NPCC Compliance Committee, a committee of the NPCC Board of Directors, manages the NPCC Compliance Monitoring and Enforcement Program (CMEP). The CMEP is used to monitor, assess and enforce mandatory compliance with both NERC continent-wide and NPCC regional standards. The CC aides in the regional standards development, as necessary, by: (1) performing compliance reviews of technical requirements, (2) assisting the drafting team with the development of Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs), Reliability Standard Audit Work Sheets (RSAWs) and (3) participating on quality review teams.
DRAFTING TEAM The drafting team develops standards-related regional products as directed by the NPCC RSC and within the scope of an approved Regional Standard Authorization Request (RSAR) or a formal Request for ClarificationInterpretation (RFIRFC). The product that is developed is 10 While RSAWs are not part of the regional standard, they are developed through collaboration of the drafting team and NPCC Compliance Staff.
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typically a new or revised regional standard, but could also be a definition, a reference document, a set of Violation Risk Factors, a set of Violation Severity levels, or the team could be appointed to assist an author in refining a Regional Standard Authorization Request (RSAR). The drafting team also works collaboratively with NPCC Compliance Staff to develop Reliability Standard Audit Worksheets (RSAWs) at the same time regional standards are developed. The drafting team shall remain in place until such time as the NERC Board of Trustees adopts the regional standard.
MANAGER OF RELIABILITY STANDARDS The NPCC Manager of Reliability Standards has the overall responsibility for managing the NPCC regional standards processes in accordance with this manual. As used herein, the NPCC Manager of Reliability Standards will be the NPCC Manager of Reliability Standards or his/her designee.
NPCC MEMBERS NPCC members may participate in the comment and ballot periods associated with the development and industry approval of regional standards. The ballot body is comprised of all entities or individuals that qualify for one of the stakeholder sectors within NPCC as stated in the most recently approved NPCC Bylaws. All General and Full Members of NPCC can participate in the balloting of regional standards. Any entity or person, including non-NPCC members, may submit comments during the open process comment periods for standards.
NON-NPCC MEMBERS Any entity or person that is neither a General nor Full Members of NPCC is not eligible to participate in the ballot body voting on a regional standard. However, any entity or person, including non-NPCC members, may submit comments during the open process comment periods for standards. Subject Matter Experts (SMEs), regardless of NPCC membership status, are encouraged to participate in comment periods for regional standards.
NPCC STANDARDS STAFF The Standards Staff is responsible for assisting the NPCC Manager of Reliability Standards and the RSC in administering the NPCC regional standards processes in accordance with this manual.
NPCC COMMITTEES, TASK FORCES AND WORKING GROUPS The Committees, Task Forces and Working Groups within NPCC serve an active role in the standards process. Activities performed by these groups include, but are not limited to, the following:
• Identify the need for new or modified regional standards
• Initiate NPCC Standards actions by developing Regional Standard Authorization Requests (RSARs)
• Develop comments (views and objections) to standards actions
• Participate in NPCC Standard drafting
• Dispensation of Request for Clarifications Interpretations (RFCIs)
• Provide technical oversight in response to changing industry conditions and ERO Requirements
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• Conduct Field Tests, as required REGIONAL STANDARDS COMMITTEE (RSC)
The NPCC Regional Standards Committee (RSC), a committee of the NPCC Board of Directors, is charged with oversight of all drafting team activities and managing the NPCC regional standards development process in accordance with this manual.
The RSC is responsible for maintenance of the Regional Standards Process ManualRegional Standard Processes Manual (RSPM), including the endorsement of RSPM revisions for NPCC Board review and approval.
RELIABILITY COORDINATING COMMITTEE (RCC) The Reliability Coordinating Committee (RCC) supports the standards development process through the assignment of NPCC Task Forces to serve as technical resources for: (1) staffing drafting teams, and (2) performing a technical advisory role in the regional standards process through comments, recommendations and technical justifications.
REQUESTER Any individual representing an organization (entity, company, government agency, etc.) that is directly and materially affected by the reliability of the Bulk Electric System within the NPCC geographical area may request a regional standard be developed or an existing regional standard be modified, interpreted, or deleted.
QUALITY REVIEW TEAM The NPCC Standards Staff shall coordinate a quality review of the “final draft” of the regional standard, implementation plan, VRFs and VSLs to assess whether the documents are within the scope of the associated RSAR, and whether the regional standard is clear and enforceable as written and the VRFs and VSLs are developed according to NERC and FERC guidelines. The Quality Review Team may be comprised of legal and compliance representatives, a technical writer, and NPCC Standards Staff. It will not involve individuals who participated on the drafting team of the standard undergoing the Quality Review.
2. STANDARD DEVELOPMENT PROCESS STEPS
STEP 2.1: REGIONAL STANDARDS AUTHORIZATION REQUEST TO DEVELOP, MODIFY OR RETIRE
A Regional Standard Authorization Request11 (RSAR) is the form used to document the scope and reliability benefit of a proposed project for one or more new or modified regional standards or the benefit of retiring one or more approved regional standards.
A RSAR shall be used to seek approval and initiate the development, modification or retirement of a NPCC regional standard. A RSAR is not used to seek a formal Request for Clarification Interpretation (RFCI) of a NPCC regional standard. The initiation and handling of a RFCI is covered in Step 3 STANDARD CLARIFICATION PROCESS STEPSSTANDARD INTERPRETATION PROCESS STEPSSTANDARD INTERPRETATION PROCESS STEPS, of this manual.
Any individual representing an organization which is directly or materially impacted by the operation of the Bulk Electric System within the geographical footprint of NPCC may request, via a submittal of a RSAR to the NPCC Manager of Reliability Standards, the development,
11 The RSAR is located on the NPCC website under Standards – Regional Standards General
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modification, or deletion of a NPCC regional standard. The individual completing the form is referred to herein as the Requester.
STEP 2.1.A. REQUESTER ACTIONS
Note: The NPCC Manager of Reliability Standards will assist the Requester, as necessary, to ensure all required information is submitted on the RSAR.
The Requester shall complete a RSAR form in accordance with the guidance provided in APPENDIX A: RSAR COMPLETION GUIDELINES.
The Requester shall submit the completed RSAR to the NPCC Manager of Reliability Standards, via [email protected], for processing.
STEP 2.1.B. NPCC MANAGER OF RELIABILITY STANDARDS ACTIONS
The NPCC Manager of Reliability Standards shall review the submitted RSAR and verify that the submitted form has been adequately completed. Within fifteen (15) calendar days 12 of receipt of the submitted RSAR, the NPCC Manager of Reliability Standards will electronically acknowledge receipt of the RSAR. If, at that time, the NPCC Manager of Reliability Standards finds the RSAR to be deficient, the Requester will be contacted to decide on how to proceed.
Within ten (10) calendar days of the receipt of an adequately completed RSAR, the NPCC Manager of Reliability Standards shall forward the properly completed RSAR to the NPCC Regional Standards Committee (RSC) for its review and processing. Included in the transmittal of the RSAR to the RSC, the NPCC Manager of Reliability Standards shall include a statement indicating the applicability of the NPCC Cost Effectiveness Analysis Procedure (CEAP) for the proposed change.
STEP 2.1.C. NPCC REGIONAL STANDARDS COMMITTEE (RSC) ACTIONS
Note: The RSC shall meet to review all pending RSARs. The frequency of this review process will depend on workload, but in no case shall a properly completed RSAR wait for RSC action more than 60 calendar days from the date of receipt by the RSC.
The RSC shall review the RSAR and take one of the following actions:
• Remand the RSAR back to the NPCC Manager of Reliability Standards for additional work. In this case, the NPCC Manager of Reliability Standards shall work with the Requester to provide may request additional information or clarification for the RSAR as specified by the RSCfrom the Requester.
• Reject the RSAR. In this case, the RSC will provide its determination to the NPCC Manager of Reliability Standards, who will then provide a written explanation for rejection to the Requester within ten (10) calendar days of the rejection decision.
12 Time periods specified in this manual may be extended as deemed appropriate by NPCC Staff. When business days are specified, this provision could be used to take into account differing Canadian and US holiday schedules. When calendar days are specified, this provision could be used to take into account due dates that fall on a weekend.
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Note: Before the RSC can accept a RSAR for a new or modified standard the applicable CEAP process steps shall be completed.
• Accept the RSAR. o If a new or modified standard has been authorized, within ten (10) calendar days of the
authorization the NPCC Manager of Reliability Standards shall: 1) post notification on the NPCC website of the intent to develop or modify a regional standard; 2) notify the ERO for processing in accordance with its process, as applicable; and 3) notify the Requester of the acceptance of the RSAR.
o If the retirement of an existing regional standard has been authorized, within ten (10) calendar days of the authorization the NPCC Manager of Reliability Standards shall: 1) post notification on the NPCC website of the intent to retire an existing regional standard; 2) notify the ERO for processing in accordance with its process, as applicable; and 3) notify the Requester of the acceptance of the RSAR. The process to retire an existing regional standard is included in Step 5 RETIREMENT OF AN APPROVED NPCC REGIONAL STANDARDRETIREMENT OF AN APPROVED NPCC REGIONAL STANDARD.
STEP 2.2: FORMATION OF DRAFTING TEAM FOR NEW OR MODIFIED STANDARD
A RSAR that has been accepted by the RSC shall, within ten (10) calendar days of the acceptance of the RSAR, be submitted by the NPCC Manager of Reliability Standards to the NPCC Reliability Coordinating Committee (RCC). The RCC shall, within sixty (60) calendar days, assign the development of the regional standard to a NPCC Task Force, and notify the NPCC Manager of Reliability Standards of its decision within ten (10) calendar days.
After receipt of the notification of drafting team assignment, the NPCC Manager of Reliability Standards shall oversee solicitation and recommendation of a list of additional qualified 13 candidates over and above the appropriate NPCC Task Force members, for appointment to the drafting team. The Requester and a NPCC Compliance Staff person will be included on the drafting team. Within sixty (60) calendar days of the drafting team assignment notification from the RCC, the NPCC Manager of Reliability Standards shall submit the list of the entire drafting team membership to the RSC for acceptance. The RSC may accept the recommendations of the NPCC Manager of Reliability Standards as presented or revise the recommendations as necessary.
Upon acceptance of the drafting team slate, the RSC shall provide a target date on which the drafting team is expected to have ready a completed draft regional standard and associated supporting documentation available for consideration by the NPCC membership. Additionally, the RSC shall provide the drafting team with any preliminary development products including, but not limited to, a draft standard, comments, and related white papers.
The RSC shall designate one of its members to actively monitor and assist NPCC staff in the oversight of drafting team milestones and deadlines, and extend or expedite milestones and deadlines, as appropriate, acting as a liaison between the drafting team and the RSC to help resolving any issues.
13 Refer to Appendix B: Selection of Drafting Team MembersAppendix B: Selection of Drafting Team Members
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STEP 2.3: DEVELOPMENT OF A REGIONAL STANDARD AND ASSOCIATED DOCUMENTS
Prior to beginning work on the development of a new or revised regional standard and the associated supporting documentation, the drafting team should develop a work plan for completing the regional standard development work, including the establishment of milestones for completing critical elements of the work in sufficient detail to ensure that the drafting team will meet the target date established by the RSC, or the drafting team shall propose an alternative date. This work plan must be submitted to the RSC for its concurrence. When a drafting team begins its work, it shall regularly (at least quarterly) report progress against that aforementioned work plan to the NPCC Manager of Reliability Standards for presentation to the RSC.
Note: During the regional standards development, the drafting team will deliberate on whether the requirements in the regional standard are developed enough to begin the Cost Effectiveness Analysis (CEA) of the NPCC Cost Effectiveness Analysis Procedure (CEAP). When appropriate, the drafting team shall request that the RSC initiate the second phase (CEA) of the CEAP process.
The drafting team shall create and manage its work structure (e.g., sub-teams) and meeting schedule (face-to face as well as electronic meetings), as necessary, to meet the milestone dates and project deliverables outlined in the work plan.
The work products of the drafting team should consist of the following
• A draft regional standard consistent with the RSAR on which it was based
• An implementation plan, including the nature, extent and duration of field-testing, if any
• Identification of any existing regional standard and NPCC criteria that will be deleted, in part or whole, or otherwise impacted by the implementation of the draft regional standard
• Technical reports, white papers and/or work papers that provide technical justification for the draft regional standard under consideration
• Reliability Standard Audit Worksheet (RSAW) collaboratively developed by the drafting team and NPCC Compliance Staff
Any proposed changes to definitions in existing regional standards should be sent to the appropriate Task Force (TF) for consideration of the impact to the standard. If necessary, the TF can produce an RSAR.
NPCC Standards Staff can assist in the drafting of the regional standard including compliance measures, process and elements. The drafting of measures and compliance administration aspects of the standard will be coordinated with the NPCC Compliance Staff.
The drafting team shall submit the initial and subsequent interim drafts of the regional standard and associated documents to the NPCC Manager of Reliability Standards to obtain RSC concurrence to post documents for comment.
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STEP 2.4: POSTING FOR COMMENT PERIOD AND RESOLUTION OF COMMENTS
Note: There are no limits to the number of public comment periods and ballots that can be conducted to result in a regional standard that is clear and enforceable, and achieves a quorum and sufficient affirmative votes for approval.
STEP 2.4.A. COMMENT PERIOD
Note: For Final Comment Period skip this step and proceed to STEP 2.4.B. FINAL COMMENT PERIOD.
As authorized by the RSC, the NPCC Manager of Reliability Standards shall post the draft of the regional standard on the NPCC website, along with a draft implementation plan and available supporting documents, for a forty-five (45) calendar day comment period. The NPCC Manager of Reliability Standards shall also notify NERC to process the draft document in accordance with NERC’s regional standards review procedure, as applicable.
Following the conclusion of the NPCC comment period, the NPCC Manager of Reliability Standards will assemble the comments on the draft regional standard and associated documents and provide all comments to the drafting team for consideration.
Within thirty (30) calendar days of the conclusion of the comment period the drafting team shall convene and consider changes to the draft Standard, the implementation plan and/or supporting technical documents based upon comments received. All submitted comments shall be addressed, and each commenter shall be advised of the disposition, with reasons, of their comments. The NPCC Manager of Reliability Standards shall publicly post all of the drafting team’s responses to stakeholder comments on the NPCC website.
Based on the comments received, the drafting team may elect to:
• Return to STEP 2.3: DEVELOPMENT OF A REGIONAL STANDARD AND ASSOCIATED DOCUMENTSSTEP 2.3: DEVELOPMENT OF A REGIONAL STANDARD AND ASSOCIATED DOCUMENTS to revise the draft regional standard, the implementation plan and/or supporting technical documents.
• Recommend that the RSC authorize Field Testing of the draft regional standard. Upon completion of the Field Test, return to STEP 2.3: DEVELOPMENT OF A REGIONAL STANDARD AND ASSOCIATED DOCUMENTSSTEP 2.3: DEVELOPMENT OF A REGIONAL STANDARD AND ASSOCIATED DOCUMENTS to revise the draft regional standard based on insights learned during the Field Test.
• Obtain RSC concurrence to post documents for Final Comment Period and request that the RSC initiate the second phase (CEA) of the CEAP process
STEP 2.4.B. FINAL COMMENT PERIOD The NPCC Standards Staff shall coordinate a Quality Review of “final draft” of the regional standard, implementation plan, VRFs and VSLs to assess whether the documents are within the scope of the associated RSAR, and whether the regional standard is clear and enforceable as written and the VRFs and VSLs are developed according to NERC and FERC guidelines. Upon Completion of the Quality Review, including resolution of comments, the drafting team shall submit the regional standard to the NPCC Manager of Reliability Standards to obtain RSC concurrence to post these documents for comment.
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As authorized by the RSC, the NPCC Standards Staff shall post the “final draft” of the regional standard on the NPCC website, along with the implementation plan, supporting documents and the Cost Effectiveness Analysis (CEA) survey14 for a forty-five (45) calendar day comment period. NPCC Standards Staff shall also notify NERC to process the proposed final document in accordance with NERC’s regional standards review procedure, as applicable.
Following the conclusion of the NPCC comment period, the NPCC Manager of Reliability Standards will assemble the comments on the posted regional standard and associated documents and provide all comments to the drafting team for consideration.
In addition, the RSC, pursuant with the requirements of the Cost Effectiveness Analysis Procedure (CEAP), will use the responses to the posted CEA survey to develop a recommendation based on the cost effectiveness of the proposed regional standard.
The NPCC Task Forces (TFs) or Working Groups (WGs) may develop recommendations for submittal to the RSC. Following the RSC deliberations to determine a course of action, the RSC will communicate to the drafting team to:
• Return to STEP 2.3: DEVELOPMENT OF A REGIONAL STANDARD AND ASSOCIATED DOCUMENTSSTEP 2.3: DEVELOPMENT OF A REGIONAL STANDARD AND ASSOCIATED DOCUMENTS to revise the Standard to address the results of the CEAP
• Accept the Standard “as is” to move forward through the remainder of the process
• Hold the Standard in abeyance until such time as additional guidance can be provided regarding whether or how to continue
• Decide not to pursue the development of certain requirements or the entire Standard due to cost effectiveness considerations
Upon Completion of the final comment period the drafting team shall submit the proposed regional standard, along with any supporting materials, consideration of comments and field test results, to the NPCC Manager of Reliability Standards to obtain RSC concurrence to post the regional standard and implementation plan for ballot and concurrently provide an information copy to the RCC.
The NPCC Manager of Reliability Standards shall also publicly post all of the drafting team’s responses to stakeholder comments on the NPCC website.
STEP 2.5: POSTING FOR BALLOT PERIOD IN THE OPEN PROCESS
Note: There are no limits to the number of public comment periods and ballots that can be conducted to result in a regional standard that is clear and enforceable, and achieves a quorum and sufficient affirmative votes for approval.
As authorized by the RSC, the NPCC Manager of Reliability Standards shall post the proposed regional standard on the NPCC website, along with supporting documentation 15 (e.g., implementation plan, consideration of comments, technical reports, white papers and any field 14 In accordance to the Cost Effectiveness Analysis Procedure (CEAP) the Cost Effectiveness Analysis (CEA) survey may be assigned directly to NPCC Task Forces (TFs) or Working Groups (WGs) in addition to the posting process. 15 The ballot posting is for the regional standard, definition, variance or interpretationclarification. Supporting
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test results), for a thirty (30) day pre-ballot review period and a subsequent ten (10) day ballot period. The ten (10) day ballot period will commence immediately following the pre-ballot review period. In the event that a quorum exists for purposes of an electronic vote but the ballot purpose has not been resolved, NPCC may continue to solicit additional responses in order to resolve the matter by electronic voting. In the event that quorum has not been achieved for purposes of an electronic vote, NPCC may continue to solicit electronic ballots, including abstentions, to obtain quorum and resolve the matter.
At the time the regional standard is posted for ballot, the NPCC Manager of Reliability Standards shall also notify NERC to process the proposed regional standard in accordance with NERC’s regional standards review procedure, as applicable.
During the ballot period, the NPCC Members of the ballot body can cast their vote as follows:
• Affirmative, with or without comments
• Negative with comments
• Abstain In accordance with the NPCC Bylaws, a quorum and receipt of a two-thirds (2/3) affirmative majority of the weighted sector votes is required for a ballot to pass.
The NPCC Manager of Reliability Standards shall post the final outcome of the ballot process on the NPCC website.
STEP 2.5.A. BALLOT DOES NOT RECEIVE 2/3 AFFIRMATIVE VOTE If a ballot fails to achieve the 2/3 majority vote the NPCC Manager of Reliability Standards may:
• Direct the drafting team to respond to ballot comments and return to STEP 2.5: POSTING FOR BALLOT PERIOD IN THE OPEN PROCESSSTEP 2.5: POSTING FOR BALLOT PERIOD IN THE OPEN PROCESS to re-ballot the regional standard. The consideration of comments from prior ballot will be included with the re-posting.
• Return to STEP 2.3: DEVELOPMENT OF A REGIONAL STANDARD AND ASSOCIATED DOCUMENTSSTEP 2.3: DEVELOPMENT OF A REGIONAL STANDARD AND ASSOCIATED DOCUMENTS to revise the regional standard to address the comments received.
• Pursue the curtailment of the regional standard development by soliciting the Requester to withdraw the RSAR or by soliciting the RSC to reject the RSAR pursuant with STEP 2.1.C. NPCC REGIONAL STANDARDS COMMITTEE (RSC) ACTIONS. The NPCC Manager of Reliability Standards, in the event of a curtailment of the development of a regional standard, shall post a notice of the curtailment and will post and archive all comments submitted during the process for future consideration, if required. The NPCC Manager of Reliability Standards will also notify NERC to process the proposed regional standard in accordance with NERC’s regional standards review procedure, as applicable.
STEP 2.5.B. BALLOT RECEIVES ≥ TWO-THIRDS (2/3) AFFIRMATIVE VOTE A ballot that achieved two-thirds or greater affirmative vote has successfully passed. However, negative votes with comments should still be reconciled. If there is at least one negative vote with comments proceed to STEP 2.5.B.1 APPROVED BALLOT WITH “NEGATIVE VOTE WITH
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COMMENT”. If there was not any negative vote with comments proceed to STEP 2.5.B.2 APPROVED BALLOT WITHOUT “NEGATIVE VOTE WITH COMMENT”.
STEP 2.5.B.1 APPROVED BALLOT WITH “NEGATIVE VOTE WITH COMMENT” Following the conclusion of the NPCC ballot period, the NPCC Manager of Reliability Standards will assemble the comments on the posted regional standard and provide all comments to the drafting team for consideration. The drafting team shall review all negative votes with comments and elect to:
• Recommend to the RSC to accept the regional standard “as is” and seek RSC endorsement to move forward through the remainder of the process. Upon receiving RSC endorsement to proceed, the regional standard and associated documents, approved by the NPCC ballot body, shall be forwarded by the Assistant Vice President Standards to the NPCC Board of Directors for final Regional approval. If comments that were received during balloting should be considered in future revisions to the regional standard then the NPCC Manager of Reliability Standards should log comments in an issues database.
• Return to STEP 2.3: DEVELOPMENT OF A REGIONAL STANDARD AND ASSOCIATED DOCUMENTSSTEP 2.3: DEVELOPMENT OF A REGIONAL STANDARD AND ASSOCIATED DOCUMENTS to revise the regional standard to address the comments received.
• Respond to ballot comments and recommend to the RSC endorse the return to STEP 2.5: POSTING FOR BALLOT PERIOD IN THE OPEN PROCESSSTEP 2.5: POSTING FOR BALLOT PERIOD IN THE OPEN PROCESS to re-ballot the regional standard. The NPCC Manager of Reliability Standards should include the consideration of comments from the prior ballot with the re-posting.
STEP 2.5.B.2 APPROVED BALLOT WITHOUT “NEGATIVE VOTE WITH COMMENT” Regional standard and associated documents, approved by the NPCC ballot body, shall be forwarded by the Assistant Vice President Standards to the NPCC Board of Directors for final Regional approval.
STEP 2.6: NPCC BOARD OF DIRECTORS APPROVAL
Following approval by the NPCC Members, regional standards require review and approval by the NPCC Board of Directors. The NPCC Board of Directors may take the following actions:
• Approve the regional standard as presented.
• Approve the regional standard with comments to incorporate non-substantive revisions. [The NPCC Board of Directors may not make substantive revisions to the standard.]
• Remand the regional standard back to the RSC and the drafting team to address their concerns.
STEP 2.7: NERC BOARD OF TRUSTEES SUBMITTAL
Upon approval by the NPCC Board of Directors, the NPCC Manager of Reliability Standards shall submit the regional standard to NERC, as the Electric Reliability Organization, for approval and subsequent filing with FERC and the applicable Canadian Provincial regulatory and/or governmental authorities for adoption.
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STEP 2.8: IMPLEMENTATION OF A NPCC REGIONAL STANDARD
Following the approval of a NPCC regional standard by FERC and the applicable Canadian Provincial regulatory and/or governmental authorities, all users, owners, planners, and operators of the Bulk Electric System in the NPCC geographic area are required to comply with the standard as of its enforcement date.
ERO approved Reliability Standards (both continent-wide and regional) are included in both the NERC and NPCC Compliance Monitoring and Enforcement Programs (CMEPs).
FIGURE 1: FLOWCHART OF REGIONAL STANDARDS DEVELOPMENT PROCESS Placeholder for flowchart
3. STANDARD CLARIFICATION INTERPRETATION PROCESS STEPS
This section applies to NPCC regional standards that have been approved16 and are currently enforceable or have a future enforcement date. A request for clarification interpretation is not permitted for regional standards under development. For regional standards under development, clarification can be sought during a comment period. Refer to Step 2, STANDARD DEVELOPMENT PROCESS STEPSSTANDARD DEVELOPMENT PROCESS STEPS of this manual for details on the comment process for a standard under development.
STEP 3.1: REGIONAL STANDARDS REQUEST FOR CLARIFICATION INTERPRETATION (RFCI)
Any member of NPCC or group within the NPCC region shall be allowed to submit a formal Request for Clarification Interpretation (RFCI) of a NPCC regional standard.
Additionally, any person (organization, company, government agency, individual, etc.) who is directly and materially affected by the reliability of the NPCC Bulk Electric System shall be allowed to submit a formal Request for Clarification Interpretation (RFCI) of a NPCC regional standard.
Note: A valid clarification interpretation request is one that seeks additional clarity about one or more requirements in an approved regional standard, but does not request approval as to how to comply with any requirements of the standard.
Request for Clarification Interpretation of a NPCC regional standard shall be initiated under the NERC process for developing an interpretation. The entity requesting the clarification interpretation shall submit a Request for Interpretation form17 to the NERC Reliability Standards Staff explaining the clarification required, the specific circumstances surrounding the request, and the impact of not having the clarification interpretation provided. A copy of the completed RFI form should also be sent to the NPCC Manager of Reliability Standards.
Upon receipt of a RFI for a requirement of a NPCC regional standard, NERC Reliability Standards Staff shall forward the RFI to the NPCC Manager of Reliability Standards and in doing so shall delegate the validation of and response to the RFI to NPCCNERC had agreed with NPCC that upon receipt of a NERC RFI for a requirement of a NPCC regional standard, NERC Reliability Standards Staff will refer the RFI to NPCC and delegate its resolution to NPCC.
16 Approval is granted by FERC and the Canadian Provincial regulatory and/or governmental authorities, as
applicable. 17 The Request for Interpretation form is posted under Resource Documents on the NERC Standards webpage.
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NPCC will process the NERC delegation pursuant with the NPCC Request for Clarification process described herein.
STEP 3.2: REVIEW AND VALIDATION OF REQUEST FOR CLARIFICATION INTERPRETATION (RFCI)
Upon receipt of the NERC delegation to NPCC to validate and respond to a RFCI for a requirement of a NPCC regional standard, the NPCC Manager of Reliability Standards shall review the RFCI to determine whether:
• It meets the requirements for a valid request for clarificationinterpretation
• A compliance process or approach could be used in lieu of an clarificationinterpretation The NPCC Manager of Reliability Standards will utilize, as necessary, the NPCC Standards Staff, NPCC Compliance and Legal Staffs when determining the validity of the RFCI. Based on this review, the NPCC Manager of Reliability Standards will recommend to the RSC whether to accept or reject the RFCI. The recommendation to the RSC should be made within thirty (30) calendar days of the receipt of the RFCI from NERC.
The following examples identify situations that may warrant a recommendation from the NPCC Manager of Reliability Standards to reject the RFCI:
• Requests approval of a particular compliance approach
• Identifies a gap or perceived weakness in the approved regional standard (Requester should be redirected to initiate an RSAR rather than a RFCI)
• Where an issue can be addressed by an active (regional or continent-wide) standard drafting team
• Where an issue can be better addressed by a compliance process or approach
• Where it requests clarification of any element of a regional standard other than a requirement
• Where a question has already been addressed in the record
• Where the clarification interpretation identifies an issue and proposes the development of a new or modified regional or continent-wide standard (such issues should be addressed via submission of a RSAR or SAR)
• Where an clarification interpretation seeks to expand the scope of a regional standard
• Where the requirement of the regional standard is clear
STEP 3.3: NPCC REGIONAL STANDARDS COMMITTEE (RSC) ACTIONS
The RSC shall review the RFI RFC along with the recommendation from the NPCC Manager of Reliability Standards and take one of the following actions:
• Reject the RFIRFC. In this case, the RSC will provide its determination to the NPCC Manager of Reliability Standards, who will then provide a written explanation for rejection to the RFCI to the entity requesting the clarification interpretation within ten (10) calendar days of the decision to reject.
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• Accept the RFIRFC. In this case, the RSC will provide its determination to the NPCC Manager of Reliability Standards, who will then: 1) post notification on the NPCC website of the intent to develop an clarificationinterpretation; 2) notify the ERO for processing in accordance with its process, as applicable; 3) assign the resolution of the RFCI to one or more Task Forces (if more than one Task Force is assigned, one of them shall be assigned the lead role); and 34) notify the Requester of the acceptance of the RFCI.
STEP 3.4: FORMATION OF DRAFTING TEAM FOR RESPONSE TO RFIRFC
A RFCI that has been accepted by the RSC shall, within ten (10) calendar days of the acceptance of the RFCI, be assigned by the NPCC Manager of Reliability Standards to the responsible NPCC Task Force to make up the clarification interpretation drafting team (ICDT) and develop the RFI RFC response.
STEP 3.5: DEVELOPMENT OF RESPONSE TO RFIRFC
Note: A valid clarification 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.
The drafting team shall submit a proposed interpretation response wWithin forty-five (45) calendar days, from the receipt of the being assigned to respond to a RFCI, the drafting team shall submit a proposed clarification interpretation response to the NPCC Manager of Reliability Standards. Upon receipt of the proposed clarification interpretation response from the drafting team, the NPCC Manager of Reliability Standards shall present the response to the to obtain RSC to obtain concurrence to post the proposed response for comment.
Along with the proposed clarification interpretation response, the drafting team shall also develop and submit a set of questions to be included in the comment form, for approval by the RSC.
If the RSC concurrence is not received, the drafting team will continue to refine the clarification interpretation response.
Note: There are no limits to the number of public comment periods that can be conducted to result in a clear and concise clarification interpretation of a regional standard requirement.
STEP 3.6: POSTING RFI RFC FOR COMMENT PERIOD AND RESOLUTION OF COMMENTS
As authorized by the RSC, the NPCC Manager of Reliability Standards shall post the proposed clarification interpretation response on the NPCC website for a forty-five (45) calendar day comment period. NPCC Manager of Reliability Standards shall also notify NERC for processing in accordance with NERC’s regional standards review procedure, as applicable.
Following the conclusion of the NPCC comment period, the NPCC Manager of Reliability Standards will assemble the comments on the proposed clarification interpretation response and provide all comments to the drafting team for consideration.
Within thirty (30) calendar days of the conclusion of the comment period the drafting team shall convene and consider changes to the proposed clarification interpretation response based upon comments received. All submitted comments shall be addressed, and each commenter shall be advised of the disposition, with reasons, of their comments. The NPCC Manager of Reliability
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Standards shall publicly post all of the drafting team’s responses to stakeholder comments on the NPCC website.
Based on the comments received, the drafting team may elect to:
• Return to STEP 3.5: DEVELOPMENT OF RESPONSE TO RFISTEP 3.5: DEVELOPMENT OF RESPONSE TO RFI to revise the proposed clarification interpretation response.
• Accept the proposed clarification interpretation response “as is” to move forward through the remainder of the process.
Upon Completion of the final comment period the drafting team shall submit the proposed clarification interpretation response to the NPCC Manager of Reliability Standards to obtain RSC concurrence endorsement to the submitted proposed interpretationRFCI response.
The NPCC Manager of Reliability Standards shall also publicly post all of the drafting team’s responses to stakeholder comments on the NPCC website.
STEP 3.7: REGIONAL STANDARDS COMMITTEE APPROVAL OF RFCI
Upon receipt of the RFCI response from the NPCC Manager of Reliability Standards, the RSC shall elect to:
• Endorse the proposed clarification interpretation response and direct the NPCC Assistant Vice President Standards to forward the RFCI to the NPCC Board of Directors for final Regional approval; or
• Direct the drafting team to return to STEP 3.5: DEVELOPMENT OF RESPONSE TO RFISTEP 3.5: DEVELOPMENT OF RESPONSE TO RFI to revise the proposed clarification interpretation response
• Direct the Assistant Vice President Standards to forward the RFI to the NPCC Board of Directors for final Regional approval
STEP 3.8: NPCC BOARD OF DIRECTORS APPROVAL OF RFCI
Following endorsement by the RSC, clarification interpretation responses require review and approval by the NPCC Board of Directors. The NPCC Board of Directors may take the following actions:
• Approve the clarification interpretation response as presented
• Approve the clarification interpretation response with comments to incorporate non-substantive revisions. [The NPCC Board of Directors may not make substantive revisions to the clarification interpretation response.]
• Remand the clarification interpretation response back to the RSC and the drafting team to address their concerns
Upon receipt of Board approval, the NPCC Manager of Reliability Standards shall notify NERC of the approved clarificationinterpretation for processing in accordance with NERC procedures, as applicable.
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FIGURE 2: FLOWCHART OF REGIONAL STANDARDS CLARIFICATIONINTERPRETATION PROCESS
Placeholder for flowchart
4. CURTAILMENT OF REGIONAL STANDARD DEVELOPMENT
The term “curtailment” as used herein refers to terminating the standard development process after RSAR approval but prior to posting a regional standard for industry ballot. From time to time the need or rationale for a regional standard may change thereby necessitating the regional standard development be curtailed. Upon notification or determination that a regional standard under development should be considered for curtailment due to a perceived change in the need for the standard, the NPCC Manager of Reliability Standards will submit the recommendation for curtailment to the RSC for approval.
4.5. WITHDRAWAL OF A REGIONAL STANDARD PENDING APPROVAL
The term “withdrawal” as used herein, refers to the revocation of a request for approval of a regional standard, variance, clarification interpretation or definition that has been approved by the NPCC Board of Directors and has not been filed with Applicable Governmental Authorities or has been filed but not yet approved by Applicable Governmental Authorities. The RSC may withdraw a regional standard, variance, clarification interpretation or definition for good cause upon subject to approval by the NPCC Board of Directors. Upon approval by the NPCC Board of Directors, the NPCC Manager of Reliability Standards will notify NERC Staff to petition the Applicable Governmental Authorities, as necessary, to allow for withdrawal in the case that the regional standard has been filed.
5.6. RETIREMENT OF AN APPROVED NPCC REGIONAL STANDARD
The term “retirement” refers to the discontinuation of a regional standard in whole, certain requirements within a regional standard, a variance, clarification interpretation or definition that: 1) has been approved by Applicable Governmental Authorities and 2) is not being superseded by or merged into a new or revised regional standard, clarification interpretation or definition.
Upon identification of a need for retirementto retire a regional standard, variance, interpretation or definition, where the item will not be superseded by a new or revised version, a RSAR containing the proposal of theo retirement a regional standard, variance, interpretation or definition will be handled in accordance with the STEP 2.1: REGIONAL STANDARDS AUTHORIZATION REQUEST TO DEVELOP, MODIFY OR RETIREposted for a comment period and ballot in the same manner as a Reliability Standard. The proposal shall include the rationale for the retirement and a statement regarding the impact of retirement on the reliability of the Bulk Electric System. Upon approval by the NPCC Members and the NPCC Board of Directors, the NPCC Manager of Reliability Standards shall submit the request for retirement to NERC, as the Electric Reliability Organization, for approval and to subsequently petition the Applicable Governmental Authorities to allow for retirement.
6.7. APPROVAL OF PROCESS WAIVER
While it is NPCC’s intent to adhere to this manual under normal circumstances, NPCC may need to develop a new or modified regional standard, implementation plan, variance, clarification interpretation or definition under extenuating circumstances. Extenuating circumstances may include, but not be limited to, specific time constraint imposed by a regulatory body and urgent
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reliability issue that requires expedited handling outside of the normal regional Reliability Standards process.
The RSC, by two-thirds (2/3) majority vote, may waive any of the provisions contained in this manual for good cause shown, but limited to the following circumstances:
• Where necessary to meet regulatory deadlines
• Where necessary to address an urgent reliability issue identified by regulatory and/or governmental authorities, including response to national emergency declared by the United States or Canadian government that involves the reliability of the Bulk Electric System or cyber-attack on the Bulk Electric System
• Where necessary to meet deadlines imposed by the NPCC Board of Directors
• Where the RSC determines that a revision to a proposed regional standard, implementation plan, variance, clarification interpretation or definition has already been vetted by the industry through the standards development process or is so insubstantial that developing the revision through the processes contained in this manual will add significant time delay without any corresponding benefit.
In no circumstances shall this provision be used to modify the requirements for achieving quorum or the voting requirements for approval of a standard.
A waiver request may be submitted to the RSC by any entity or individual, including NPCC committees or subgroups and NPCC Standards Staff. Prior to consideration of any waiver request, the NPCC Manager of Reliability Standards must provide notification to stakeholders at least five (5) business days prior to RSC consideration and action. Posting the waiver request on the NPCC website satisfies the notification provision. Action on the waiver request will be included in the minutes of the RSC. Following the approval of the RSC to waive any provision of the regional Reliability Standards process, the Assistant Vice President Standards shall report the exercise of this waiver provision to the NPCC Board of Directors prior to adoption of the related Reliability Standard, clarificationinterpretation, definition or variance. Actions taken pursuant to an approved waiver request will be posted on the NPCC Standards webpage.
In addition,
7.8. PROCESS FOR CORRECTING ERRATA
From time to time, an error may be discovered in a regional standard after it has received final ballot approval by the NPCC ballot body. Such errors may be corrected by the RSC without re-balloting if the RSC agrees that the correction of the error does not change the scope or intent of the associated regional standard, and agrees that the correction has no material impact on the end users of the regional standard.
If the regional standard containing errata is pending approval by the NPCC Board of Directors, the corrected regional standard shall be presented to the NPCC Board for approval in lieu of the regional standard approved by the NPCC ballot body.
If a regional standard containing errata had received prior approval by the NPCC Board of Directors, the corrected regional standard shall be presented to the NPCC Board for approval. Upon approval by the Board, the corrected regional standard will be filed for approval by NERC.
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The NPCC Board of Directors has resolved to concurrently approve any errata approved by the RSC associated with a regional standard that has received prior approval by the NPCC Board. If the regional standard containing errata is:
• Pending filing with NERC for approval, the corrected regional standard approved by the RSC shall be filed with NERC for approval in lieu of the regional standard approved by the NPCC Board of Directors
• Filed with NERC for approval, then the correction shall be filed for approval with NERC 8.9. APPEALS
Persons who have directly and materially affected interests and who have been or will be adversely affected by any substantive or procedural action or inaction related to the approval, revision, reaffirmation, or withdrawal of a regional standard (appellant) shall have the right to appeal. This appeals process applies only to the regional standards process as defined in this manual.
The burden of proof to show adverse effect shall be on the appellant. Appeals shall be made within thirty (30) calendar days of the date of the action purported to cause the adverse effect, except appeals for inaction, which may be made at any time. In all cases, the request for appeal must be made prior to the next step in the process.
The final decisions of any appeal shall be documented in writing and made public.
The appeals process provides two levels, with the goal of expeditiously resolving the issue to the satisfaction of the participants:
LEVEL 1 APPEAL
Level 1 is the required first step in the appeals process. The appellant submits a complaint in writing to the NPCC Manager of Reliability Standards that describes the substantive or procedural action or inaction associated with a Reliability Standard or the standards process. The appellant describes in the complaint the actual or potential adverse impact to the appellant. Assisted by any necessary NPCC Standards Staff and Committee resources, the NPCC Manager of Reliability Standards shall prepare a written response addressed to the appellant as soon as practical, but not more than forty-five (45) calendar days after receipt of the complaint. If the appellant accepts the response as a satisfactory resolution of the issue, both the complaint and response will be made a part of the public record associated with the standard and posted with the standard.
LEVEL 2 APPEAL
If after the Level 1 Appeal the appellant remains unsatisfied with the resolution, as indicated by the appellant in writing to the NPCC Manager of Reliability Standards, the NPCC Board of Directors shall appoint a five member panel to serve as a Level 2 Appeals Panel.
In all cases, Level 2 Appeals Panel members shall have no direct affiliation with the participants in the appeal.
The NPCC Manager of Reliability Standards shall post the complaint and other relevant materials and provide at least a thirty (30) calendar day notice of the meeting of the Level 2 Appeals Panel.
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In addition to the appellant, any person that is directly and materially affected by the substantive or procedural action or inaction referenced in the complaint shall be heard by the panel. The panel shall not consider any expansion of the scope of the appeal that was not presented in the Level 1 Appeal. The panel may in its decision find for the appellant and remand the issue to the RSC with a statement of the issues and facts in regard to which unfair and/or inequitable action was taken, or which fair and/or equitable action was not taken. The panel may find for or against the appellant with a specific statement of the facts that demonstrate fair and equitable treatment of the appellant and the appellant’s objections. The panel may not, however, revise, approve, disapprove, or adopt a Reliability Standard. The actions of the Level 2 Appeals Panel shall be publicly posted.
In addition to the foregoing, a procedural objection that has not been resolved may be submitted to the NPCC Board of Directors for consideration at the time the Board decides whether to adopt a particular Reliability Standard. The objection must be in writing, signed by an officer of the objecting entity, and contain a concise statement of the relief requested and a clear demonstration of the facts that justify that relief. The objection must be filed no later than thirty (30) calendar days after the announcement of the vote on the standard in question.
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APPENDIX A: RSAR COMPLETION GUIDELINES The Requester shall complete a RSAR form in accordance with the guidance provided below.
The RSAR, at a minimum, shall contain information in the required fields in order to be qualified for consideration. The NPCC Manager of Reliability Standards will assist the Requester to ensure all required information is submitted on the RSAR.
Information in a Regional Standard Authorization Request (RSAR) The tables below identify information to be submitted in a Regional Standard Authorization Request to the NPCC Manager of Reliability Standards, at [email protected]. The NPCC Manager of Reliability Standards shall be responsible for implementing and maintaining this form as needed to support the information requirements of the standards process.
Regional Standard Authorization Request Form Title of Proposed Standard: [Required Field]
Request Date: [Required Field]
RSAR Requester Information
Name: [Required Field] RSAR Type (Check box for one of these selections.)
Company: [Required Field] New Standard
Telephone: [Required Field] Revision to Existing Standard
Fax: Withdrawal of Existing Standard
Email: [Required Field] Urgent Action
Purpose: (Describe the purpose of the proposed standard – what the standard will achieve in support of reliability.)
[Required Field]
Industry Need: (Provide a detailed statement justifying the need for the proposed standard, along with a technical justification and any supporting documentation.)
[Required Field -- must include technical justification (relevant studies, documentation, etc.) for a new standard or revision to an existing standard.]
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Brief Description: (Describe the proposed standard in sufficient detail to clearly define the scope in a manner that can be easily understood by others.)
[Required Field]
Reliability Functions [Required Field] The Standard will Apply to the Following Functions (Check all applicable boxes.)
Reliability Coordinator
The entity that is the highest level of authority who is responsible for the reliable operation of the Bulk Electric System, has the Wide Area view of the Bulk Electric System, and has the operating tools, processes and procedures, including the authority to prevent or mitigate emergency operating situations in both next-day analysis and real-time operations. The Reliability Coordinator has the purview that is broad enough to enable the calculation of Interconnection Reliability Operating Limits, which may be based on the operating parameters of transmission systems beyond any Transmission Operator’s vision.
Balancing Authority
The responsible entity that integrates resource plans ahead of time, maintains load-interchange-generation balance within a Balancing Authority Area, and supports Interconnection frequency in real time.
Interchange Authority
Authorizes valid and balanced Interchange Schedules.
Planning Authority
The responsible entity that coordinates and integrates transmission facility and service plans, resource plans, and protection systems.
Transmission Service Provider
The entity that administers the transmission tariff and provides Transmission Service to Transmission Customers under applicable transmission service agreements.
Transmission Owner
The entity that owns and maintains transmission facilities.
Transmission Operator
The entity responsible for the reliability of its “local” transmission system, and that operates or directs the operations of the transmission facilities.
Transmission Planner
The entity that develops a long-term (generally one year and beyond) plan for the reliability (adequacy) of the interconnected bulk electric transmission systems within its portion of the Planning Authority Area.
Resource Planner
The entity that develops a long-term (generally one year and beyond) plan for the resource adequacy of specific loads (customer demand and energy requirements) within a Planning Authority Area.
Generator Operator
The entity that operates generating unit(s) and performs the functions of supplying energy and Interconnected Operations Services.
Generator Owner
Entity that owns and maintains generating units.
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Purchasing-Selling Entity
The entity that purchases or sells, and takes title to, energy, capacity, and Interconnected Operations Services. Purchasing-Selling Entities may be affiliated or unaffiliated merchants and may or may not own generating facilities.
Distribution Provider
Provides and operates the “wires” between the transmission system and the customer.
Load-Serving Entity
Secures energy and transmission service (and related Interconnected Operations Services) to serve the electrical demand and energy requirements of its end-use customers.
Reliability and Market Interface Principles Applicable Reliability Principles (Check all boxes that apply.)
1. Interconnected Bulk Electric System 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 Electric System 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 Electric System 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 Electric System 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 Electric System.
6. Personnel responsible for planning and operating interconnected Bulk Electric System shall be trained, qualified, and have the responsibility and authority to implement actions.
7. The security of the interconnected Bulk Electric System shall be assessed, monitored, and maintained on a wide-area basis.
Does the proposed Standard comply with all of the following Market Interface Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)
Recognizing that reliability is an Common Attribute of a robust North American economy:
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
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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
Detailed Description: (Provide enough detail so that an independent entity familiar with the industry could draft a standard based on this description.)
[Required Field – Provide: 1) Necessary information to assist the drafting team (which is to include relevant study results and documentation), to the extent feasible, to allow them to draft the standard, 2) Any existing known cross references to NPCC or NERC documents and 3) Technical background for the RSAR to properly address the need for the standard.]
Related Standards [Required Field, to extent known] Standard No. Explanation
Related SARs or RSARs [Required Field, to extent known] SAR ID Explanation
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APPENDIX B: SELECTION OF DRAFTING TEAM MEMBERS A regional standard drafting team shall be comprised of Subject Matter Experts (SMEs) from NPCC Task Forces and Working Groups as determined by the RCC, and from industry. The guidelines provided herein primarily address overall team requirements and more specifically those of a SME.
Formal membership on a drafting team should be reserved only for those individuals who intend to work consistently, diligently, and professionally on what is required to be done for a regional standard. drafting team members are expected to contribute meaningfully to the ongoing development of the standard.
Drafting team members must be:
• Committed to participating in scheduled drafting team meetings, teleconferences, as well as industry outreach (e.g., workshops and webinars)
• Willing to lead teams / sub-teams, as necessary
• Champions for standard development and promoters of the approval of the standard
• Open to consider the comments of others and provide constructive feedback
Subject Matter Experts should possess the necessary expertise and knowledge regarding the topic of the standard. The SMEs should represent a cross section of the registered entities applicable to the standard under development as well as geographical areas within the NPCC footprint.
Industry stakeholders may nominate themselves for consideration by the NPCC Regional Standards Committee (RSC) for the specific drafting team vacancies by completing the following drafting team Self Nomination form and submitting it to NPCC Manager of Reliability Standards, at [email protected].
Nomination Form for NPCC [Name of drafting team] Drafting Team Please return this form as soon as possible. If you have any questions, please contact the NPCC Standards Staff at [email protected].
By submitting the following information you are indicating your willingness and agreement to actively participate in the drafting team meetings if appointed to the drafting team by the NPCC Regional Standards Committee (RSC). This means that if you are appointed to the DT you are expected to attend all (or at least the vast majority) of the face-to-face DT meetings as well as participate in all the DT meetings held via conference calls. Failure to do so shall result in your removal from the DT.
Name:
Organization:
Address:
Telephone:
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E-mail:
Please briefly describe your experience and qualifications to serve on the requested drafting team.
If you are currently a member of any NERC or Regional drafting teams, please list each team here. Not currently on any active SAR or standard drafting team. Currently a member of the following SAR or standard drafting team(s):
If you previously worked on any drafting team please identify the team(s). No prior NERC or Regional SAR or standard drafting team experience. Prior experience on the following team(s):
Select each NERC Region that you represent: Select each Industry Segment that you represent:
ERCOT FRCC MRO NPCC RFC SERC SPP WECC NA – Not Applicable
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, and Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations and Regional Entities
NA – Not Applicable
Select each Function18 in which you have current or prior expertise:
Balancing Authority Compliance Enforcement Authority Distribution Provider Generator Operator Generator Owner Interchange Authority Load-serving Entity Market Operator Planning Coordinator
Transmission Operator Transmission Owner Transmission Planner Transmission Service Provider Purchasing-selling Entity Reliability Coordinator Reliability Assurer Resource Planner
18 These functions are defined in the NERC Functional Model, which is downloadable from the NERC website.
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Provide the names and contact information for two references who could attest to your technical qualifications and your ability to work well in a group.
Name: Telephone:
Organization: E-mail:
Name: Telephone:
Organization: E-mail:
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APPENDIX C: MAINTENANCE OF REGIONAL STANDARDS AND PROCESS NPCC regional standards and the Regional Standards Process ManualRegional Standard Processes Manual are living documents that will be updated periodically to remain current and viable (e.g., respond to changing conditions, as well as to incorporate lessons learned and process improvements).
MAINTENANCE OF REGIONAL STANDARDS
NPCC regional standards will be posted for open process review by the RSC for possible revision at least once every five (5) years after the first regulatory approval and follow the same process as in the case of a new standard. If no changes are warranted, the Regional Standards Committee (RSC) shall recommend to the NPCC Board that the standard be reaffirmed. If the review indicates a need to revise or retire a regional standard, a Regional Standard Authorization Request shall be prepared by the RSC and submitted in accordance with the NPCC regional standards process. The existing, approved standard subject to revision will remain in effect until such time as the revised version has received FERC or applicable Provincial Governmental Authorities approvals, as appropriate, at which time it will be retired in accordance with any applicable implementation plan associated with the newly approved regional standard.
MAINTENANCE OF THE REGIONAL STANDARDS PROCESS
This NPCC Regional Standards Process will be reviewed for possible revision at least once every five (5) years, or more frequently if needed, and subject to the same procedure as applies to the development of a Regional Standard. All such revisions shall be subject to approval by the NPCC Board of Directors, NERC Board of Trustees, FERC, and may be subject to approval, if required, by Applicable Governmental Authorities in Canada.
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Comment No.
Section/Page No. Comment Disposition of Comment1
1 PSEG Comment NPCC Q1 – Yes, CEAP appropriately situated in document
General statement
2 Step 3.2 PSEG Comment NPCC Q2 – No: The IDT should determine whether or not the issues identified in the RFI warrant an RSAR, not the Manager of Reliability Standards. The Manager or Reliability Standards should manage the process as opposed to participating in it.
Comment not incorporated – RFI must be screened and determined to be valid prior to formation of an Interpretation Drafting Team (IDT). At NPCC, the NPCC Manager of Reliability Standards performs the initial screening (utilizing, as necessary, the NPCC Standards Staff, NPCC Compliance and Legal Staffs) prior to making a recommendation to the Regional Standards Committee on how to proceed. This process is similar to the NERC process which has the NERC Reliability Standards and Legal Staffs review the request for interpretation prior to the Standards Committee authorizing the RFI to proceed and an IDT formed.
3 PSEG Comment NPCC Q3 – The manual should have a process for retiring a regional standards development project once it has been initiated by an RSAR. Otherwise, an RSAR that becomes a project cannot be halted unless the project team completes its mission, even though the rationale for the project may have changed.
Comment incorporated – new Section 4 [As initially drafted, the RSPM allows for curtailment of regional standard development when a ballot does not reach a 2/3 majority vote. The incorporation of the review comment allows for curtailment of regional standard development at any time after RSAR approval]
4 NPCC Comment: Revise document title from “Regional Standards Process Manual” to “Regional Standard Processes Manual”
Comment incorporated
5 Section IV.1, page 9
NPCC Comment: Not sure the CC needs to be specifically referenced on Page 9: The NPCC Compliance Committee, a committee of the NPCC Board of Directors, manages the NPCC Compliance Monitoring and Enforcement Program
Comment incorporated – specific reference to CC has been removed from the RSPM
1 Comment Dispositions: Comment incorporated; General statement (no action required); Future consideration (with explanation); Comment not incorporated (with explanation)
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RSC October 2013 Meeting Item 5.2b
Comment No.
Section/Page No. Comment Disposition of Comment1
(CMEP). The CMEP is used to monitor, assess and enforce mandatory compliance with both NERC continent-wide and NPCC regional standards. The CC aides in the regional standards development, as necessary, by: (1) performing compliance reviews of technical requirements, (2) assisting the Drafting Team with the development of Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs), Reliability Standard Audit Work Sheets (RSAWs) and (3) participating on quality review teams.” …and it is not an accurate statement.
• The CC has never done #1. • The CC does not do #2 as written. Ben is using a
special CCWG to accomplish the RSAW for DME. The CC is not “assisting the drafting team with the development of the RSAW”.
• The CC has never done #3. • The CC does not manage the NPCC CMEP. The
CC only reviews the Annual CMEP Implementation Plan.
The only sentence that I feel is accurate is: The CMEP is used to monitor, assess and enforce mandatory compliance with both NERC continent-wide and NPCC regional standards. Why create a whole distinct paragraph for the CC to begin with? Perhaps the CC could be identified as a player instead on an “as necessary” basis on Page 10 of the draft document? Personally, I do not think the CC needs to be specifically spelled-out in the document; unless there is some political aspect at play here. If NPCC is going to put #1, #2, #3 in the RSPM then our CC Scope would have to be adjusted, which is ok, but the tasks have to have a realistic chance of coming to fruition if we are
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RSC October 2013 Meeting Item 5.2b
Comment No.
Section/Page No. Comment Disposition of Comment1
going to do that. 6 NPCC Comment:
Capture the concept of replacing “Interpretations” with Clarifications. The latter would not be voted on by the stakeholders and filed, similar to what we do today
Comment incorporated
7 Section IV.1
ConEd Comment: QUESTION: Has the Compliance Committee (CC) role been reviewed by the CC and do they agree? We understand that there is a caveat, e.g., "as necessary" that leaves room for future discussion. However, it does not say who decides what and when such assistance is "necessary."
Refer to Comment No. 6
8 Section IV.1
Hydro One Network Comment: For NPCC Committees, Task Forces And Working Groups Process Roles And Responsibilities and the following bullet: • Dispensation of Request for Interpretations (RFIs)
Comment incorporated
9 Step 2.1.C
Hydro One Network Comment: Revise to read: “Remand the RSAR back to the NPCC Manager of Reliability Standards for additional work. In this case, the NPCC Manager of Reliability Standards shall work with the Requester to provide may request additional information or clarification for the RSAR as specified by the RSCfrom the Requester.”
Comment incorporated
10 Step 2.2 Hydro One Network Comment: Add: The RSC shall designate one of its members to actively monitor and assist NPCC staff in the oversight of Drafting Team milestones and deadlines, and extend or expedite milestones and deadlines, as appropriate, acting as a liaison between the Drafting Team and the RSC to help resolving any issues.
Comment incorporated
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Page 4 of 11
RSC October 2013 Meeting Item 5.2b
Comment No.
Section/Page No. Comment Disposition of Comment1
11 Step 2.3 Hydro One Network Comment: Add: Any changes to definitions in existing Regional Standards should be sent to the appropriate Task Force for consideration of the impact to the standard of the definition change. If necessary, the TF can produce an RSAR.
Comment incorporated
12 Step 3.1 Hydro One Network Comment: This is a NPCC document. It cannot give obligations to NERC staff or assume delegation on their part. Suggest changing “Upon receipt of a RFI for a requirement of a NPCC regional standard, NERC Reliability Standards Staff shall forward the RFI to the NPCC Manager of Reliability Standards and in doing so shall delegate the validation of and response to the RFI to NPCC.” to “NERC had agreed with NPCC that upon receipt of a RFI for a requirement of a NPCC regional standard, NERC Reliability Standards Staff will refer the RFI to NPCC and delegate its resolution to NPCC.” Questions:
• Should this delegation be formalized in the NERC SPM?
• Will Regional Standards be included in the projected NERC Single Portal?
Comment incorporated The questions are outside the scope of the RSPM revision and have been referred to NPCC Staff on the NERC Standards Committee Process Subcommittee (SCPS)
13 Step 3.2 Hydro One Network Comment: Revise bullet to read: Where it requests clarification of any element of a regional standard other than a such as purpose, applicability, effective dates and requirements but not on the compliance elements in the standard. Delete bullet:
• Where the requirement of the regional standard is clear
Comment not incorporated – The RSPM verbiage is consistent with the NERC SPM
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Page 5 of 11
RSC October 2013 Meeting Item 5.2b
Comment No.
Section/Page No. Comment Disposition of Comment1
14 Step 3.3 Hydro One Network Comment: Revise bullet to read: Accept the RFI. In this case, the RSC will provide its determination to the NPCC Manager of Reliability Standards, who will then: 1) post notification on the NPCC website of the intent to develop an interpretation; 2) notify the ERO for processing in accordance with its process, as applicable; 3) assign the resolution of the RFI to one or more Task Forces (if more than one Task Force is assigned, one of them shall be assigned the lead role) and 34) notify the Requester of the acceptance of the RFI.
Comment incorporated
15 Step 3.4 Hydro One Network Comment: Revise to read: A RFI that has been accepted by the RSC shall, within ten (10) calendar days of the acceptance of the RFI, be assigned by the NPCC Manager of Reliability Standards to the responsible NPCC Task Force to make up the interpretation Drafting Team and develop the RFI response. [It is up to the TF how it deals with the RFI, a DT may not be necessary. It should state that the RFI will be forwarded to the appropriate TF for dispensation. It is up to the TF if they feel they need to form a DT to answer the RFI].
Comment not incorporated – The Interpretation Drafting Team is the group that is responding to the RFI which can be made up in whole or in part by the Task Force (TF). The TF and the IDT are not mutually exclusive.
16 Step 3.5 Hydro One Network Comment: Revise to read: The Drafting Team shall submit a proposed interpretation response within forty-five (45) calendar days, from the receipt of the RFI, to the NPCC Manager of Reliability Standards to obtain RSC concurrence to post the proposed response for comment. The Drafting team shall also develop a set of questions to be included in the comment form, for approval by the RSC.
Comment incorporated
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Page 6 of 11
RSC October 2013 Meeting Item 5.2b
Comment No.
Section/Page No. Comment Disposition of Comment1
17 Step 3.6 Hydro One Network Comment: Revise to read: Upon Completion of the final comment period the Drafting Team shall submit the proposed interpretation response to the NPCC Manager of Reliability Standards to obtain RSC concurrence endorsement to the submitted RFI proposed interpretation response.
Comment incorporated
18 Step 3.7 Hydro One Network Comment: Revise to read:
• Endorse the proposed interpretation response and direct the Assistant Vice President Standards to forward the RFI to the NPCC Board of Directors for final Regional approval; or
• Direct the Drafting Team to return to STEP 3.5: DEVELOPMENT OF RESPONSE TO RFI to revise the proposed interpretation response
• Direct the Assistant Vice President Standards to forward the RFI to the NPCC Board of Directors for final Regional approval
Comment incorporated
19 Step 3.8 Hydro One Network Comment: Upon receipt of Board approval, the NPCC Manager of Reliability Standards shall notify NERC of the approved interpretation for processing in accordance with NERC procedures, as applicable. This is pretty gray. Why not just say “notify NERC” and stop with that. Why not add that submittal to FERC is not required or something? Only because the CC asks all the time…”Why didn’t Guy send the Interpretation to FERC?”…and they ask “What are the NERC procedures that are referred to here?”.
Comment incorporated
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Page 7 of 11
RSC October 2013 Meeting Item 5.2b
Comment No.
Section/Page No. Comment Disposition of Comment1
20 Section IV.4
Hydro One Network Comment: Revise to read: The term “withdrawal” as used herein, refers to the revocation of a request for approval of a regional standard, variance, interpretation or definition that has been approved by the NPCC Board of Directors and has not been filed with Applicable Governmental Authorities or has been filed but not yet approved by Applicable Governmental Authorities. The RSC may withdraw a regional standard, variance, interpretation or definition for good cause subject to upon approval by the NPCC Board of Directors. Upon approval by the NPCC Board of Directors, the NPCC Manager of Reliability Standards will notify NERC Staff to petition the Applicable Governmental Authorities, as necessary, to allow for withdrawal in the case that the regional standard has been filed. Question: Is any action required from the NERC BoT if the standard was adopted by the BoT?
Comment incorporated
21 Section IV.5
Hydro One Network Comment: Revise to read: The term “retirement” refers to the discontinuation of a regional standard in whole, certain requirements within a regional standard, a variance, interpretation or definition that: 1) has been approved by Applicable Governmental Authorities and 2) is not being superseded by or merged into a new or revised regional standard, interpretation or definition. Upon identification of a need for a retirement, to retire a regional standard, variance, interpretation or definition, where the item will not be superseded by a new or revised version, a RSAR containing the proposal theo retirement a regional standard, variance, interpretation or definition will be posted for a comment period and ballot in the same manner as a Reliability Standard RSAR.
Comment incorporated
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Page 8 of 11
RSC October 2013 Meeting Item 5.2b
Comment No.
Section/Page No. Comment Disposition of Comment1
22 Section IV.7
Hydro One Network Comment: Revise to read: If the regional standard containing errata is pending approval by the NPCC Board of Directors, the corrected regional standard shall be presented to the NPCC Board for approval in lieu of the regional standard approved by the NPCC ballot body. If a regional standard containing errata had received prior approval by the NPCC Board of Directors, the corrected regional standard shall be presented to the NPCC Board for approval. Upon approval by the Board, the corrected regional standard will be filed for approval by NERC. The NPCC Board of Directors has resolved to concurrently approve any errata approved by the RSC associated with a regional standard that has received prior approval by the NPCC Board. If the regional standard containing errata is:
• Pending filing with NERC for approval, the corrected regional standard approved by the RSC shall be filed with NERC for approval in lieu of the regional standard approved by the NPCC Board of Directors
• Filed with NERC for approval, then the correction shall be filed for approval with NERC
Comment incorporated
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Page 9 of 11
RSC October 2013 Meeting Item 5.2b
Comment No.
Section/Page No. Comment Disposition of Comment1
23 Hydro One Network Comment: Add words to address actions when the standard has already received full FERC approval. We actually have PRC-006-NPCC-01 which now has several issues that were not properly transcribed from D#12. What is the process then? For now NPCC has recognized there are some issues and they will be addressed in the RSAW (not sure that is the best approach). Even so there should be some mention of this. [Clarification provided: Obviously the matter should be addressed in the section dealing with modifying existing standards]
Future consideration – modification to a FERC approved regional standard should follow the process outlined in the NPCC RSPM, i.e., initiate an RSAR to revise the standard. The use of a RSAW for PRC-006-NPCC-01 was an off-normal process that I am not sure we should codify in the new RSPM. Further discussion needed.
24 Dominion Comment NERC Q1 – Yes
Noted
25 Dominion Comment NERC Q2 – Yes
General statement
26 Dominion Comment NERC Q3 – Yes
General statement
27 Dominion Comment NERC Q4 – Yes
General statement
28 Dominion Comment NERC Q5 – Yes
General statement
29 IESO Comment NERC Q1 – Yes
General statement
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RSC October 2013 Meeting Item 5.2b
Comment No.
Section/Page No. Comment Disposition of Comment1
30 IESO Comment NERC Q2 – No: We believe a major and necessary step is missing: posting the RSAR for comment after it is accepted by the RSC. Posting an RSAR for public comment ensure inclusiveness, is consistent with NERC’s standards development process, and is critical in assessing the need and merit for developing a regional standard with due inputs from NPCC members and those who may be affected by the proposed standards (or their retirement). We suggest to add this posting process.
Comment not incorporated – the RSAR is intended to provide high level guidance to the drafting team. In lieu of posting the RSAR for industry comments, stakeholders should consider: a. participating in the RSC meeting during which the RSAR is presented for approval b. responding, as necessary, to the public notification of the intent to develop, modify or retire a standard c. participating in the standard comment and ballot periods
31 IESO Comment NERC Q3 – Yes
General statement
32 IESO Comment NERC Q4 – No: Unlike the NERC process, interpretations of the NPCC regional standards do not require balloting by the NPCC’s registered ballot body. We wonder if this an oversight or is it the design of the NPCC interpretation process? If it is the latter, the rationale has not been provided in the manual. Please add the balloting step to fully meet the “due process” criteria, or provide the rationale for not having to ballot interpretations.
Comment not incorporated – the Interpretation Section of the NPCC RSPM has been replaced with a Clarifications Section (see Comment No. 6, above). It is not the intent of NPCC to ballot clarifications. With regard to due process: NPCC will post notification on the NPCC website of the intent to develop an clarification, however a clarification does not change the intent of a requirement and is therefore not subject to due process under ERO RoP Section 304
33 IESO Comment NERC Q5 – Yes: We agree the NPCC Regional Standards Process Manual continues to meet the transparent criteria. In addition, we offer the following editorial comments: a. Section 3.2 REVIEW AND VALIDATION OF REQUEST FOR INTERPRETATION (RFI): suggest to add “request for” between “valid” and “interpretation” since the only assessment that can be made at that time is whether not the request is valid, not whether or not the interpretation itself, which has yet to be developed, is valid.
a. Comment incorporated b. Comment incorporated c. Comment incorporated d. Comment incorporated e. Comment incorporated
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Page 11 of 11
RSC October 2013 Meeting Item 5.2b
Comment No.
Section/Page No. Comment Disposition of Comment1
b. Step 3.5: DEVELOPMENT OF RESPONSE TO RFI - Clarity should be added to indicate whether it’s 45 days after NPCC receives the RFI or the Drafting Team receives the charge to develop a response (i.e. the interpretation). Depending on the activities that may occur after NPCC receives the RFI, the DT may have very little time to develop a response. c. Violation Risk Factor and Violation Severity Level Section: Suggest to add “and Compliance Staff” or “the Compliance Committee” after “working with NPCC Standards Staff” since these are factors and elements that assist in compliance assessment and as such, inputs from NPCC Compliance Staff or the CC (with reference to the role of CC in Section IV - Regional Standards Development Process) should be sought. d. Suggest to add “or reference documents” after “Guideline” in the Information Element Section. e. In the Quality Review Team Section, suggest to remove the word “and” before “whether”, and append to “...is clear and enforceable as written “and the VRFs and VSLs are developed according to NERC and FERC guidelines.”
RSC October Meeting Item 6.1 RSC Meeting #13-5, Agenda Item 6.1: NERC Currently Posted Projects
Page 1 of 5
Item Name of Project Details 6.1.a Project 2008-02 -
Undervoltage Load Shedding
Summary: In response to a FERC directive relating to PRC-010-0 from Order No. 693, the
original Project 2008-02 UVLS SAR was posted for public comment in early 2010. Due to other priorities, no further action was taken until the effort was recently restarted, with a formal drafting team appointed earlier this year. The drafting team has revised the SAR and is seeking industry feedback. To support the SAR’s intention, the team is also providing and requesting feedback on draft requirements and additional supporting language for a proposed PRC-010-1.
Posted Documents: Revised SAR Supporting Materials:
o Draft Standard PRC-010-1, Automatic Undervoltage Load Shedding o Unofficial Comment Form (Word)
Key Issues: Key Dates: SAR Informal 30-day Comment period open through 8:00 p.m. ET on
October 9, 2013 6.1.b Project 2013-03 -
Geomagnetic Disturbance Mitigation
Summary: EOP-010-1 is being developed to meet the directives contained in FERC Order
No. 779 for stage 1 (Operating Procedures) standards. FERC established a January 2014 filing deadline for Stage 1 standards.
Posted Documents: EOP-010-1, Geomagnetic Disturbance Operations Implementation Plan Supporting Materials:
o Unofficial Comment Form (Word) o SAR o White Paper Supporting Network Applicability of EOP-010-1 o White Paper Supporting Functional Entity Applicability of EOP-010-1 o GMD Task Force Operating Procedures
Key Issues: Although a fairly routine process oriented standard, there is a concern that some
requirements are P-81 type. Key Dates: Additional Ballot window open through 8:00 p.m. ET on October 18, 2013 Formal 45-day Comment period open through 8:00 p.m. ET on October 18,
2013
RSC October Meeting Item 6.1 RSC Meeting #13-5, Agenda Item 6.1: NERC Currently Posted Projects
Page 2 of 5
Item Name of Project Details 6.1.c Project 2010-17 -
Definition of Bulk Electric System (Phase 2)
Summary: Phase 2 of the definition of Bulk Electric System project was initiated to develop
appropriate technical justification to support refinements to the definition that were suggested by stakeholders during Phase I, and to refine the definition as technically justified. In addition, during Phase 2 the drafting team will address FERC’s directives from Orders 773 and 773-A.
Posted Documents: Draft 2 - Phase 2 Definition Implementation Plan Supporting Materials:
o White Paper to Support sub-100 kV Threshold o SAR o Unofficial Comment Form o Notice of Request to Waive the Standard Process
Key Issues: Key Dates: Additional Ballot window open through 8:00 p.m. ET on October 28, 2013 Formal 30-day Comment period open through 8:00 p.m. ET on October 28,
2013 6.1.d Regional
Reliability Standard Interpretation for TOP-007-WECC-1
Summary: Arizona Public Service (APS) filed WECC-0010 Request for Interpretation
(Request) with Western Electricity Coordinating Council (WECC). The Request is specific to TOP-007-WECC-1, System Operating Limits; Requirement R1. Specifically APS asks for clarification that the Requirement R1 applies “to Transmission Operators, as defined in the NERC Glossary of Terms, and not to the path operators who have no compliance responsibilities under TOP-007-WECC-1 (TOP), other than any responsibilities they may have as a Transmission Operator for facilities in their respective Transmission Operator Areas.”
Posted Documents: Interpretation of TOP-007-WECC-1 Supporting Materials:
o Unofficial Comment Form (Word) o WECC Standard TOP-007-WECC-1 — System Operating Limits o Standards Announcement o Request for Interpretation of TOP-007-WECC-1 o GMD Task Force Operating Procedures
Key Issues: Key Dates: Formal 45-day Comment period open through 8:00 p.m. ET on October 29,
2013
RSC October Meeting Item 6.1 RSC Meeting #13-5, Agenda Item 6.1: NERC Currently Posted Projects
Page 3 of 5
Item Name of Project Details 6.1.e Project 2010-01 –
Training – PER-005-2
Summary: In response to Directives in FERC Order 693 and Order 742, this project modifies
PER-005 to require the use of a systematic approach to determining training needs of generator operators and operations planning and support staff with a direct impact on the reliable operations of the bulk power system.
Posted Documents: PER-005-2, Operations Personnel Training Implementation Plan Supporting Materials:
o Unofficial Comment Form (Word) o SAR o Technical White Paper o Mapping Document o Compliance Input o Proposed Timeline for the Formal Development
Key Issues: Applicability to Support Personnel – Industry does not support applicability to
EMS personnel (e.g., modeling). As defined in the posted st`1andard, PER-005-2 will not apply to EMS personnel.
Key Dates: Additional Ballot window open through 8:00 p.m. ET on November 12, 2013 Formal 45-day Comment period open through 8:00 p.m. ET on November 12,
2013
RSC October Meeting Item 6.1 RSC Meeting #13-5, Agenda Item 6.1: NERC Currently Posted Projects
Page 4 of 5
Item Name of Project Details 6.1.f Project 2008-12 -
Coordinate Interchange Standards - Various INT standards
Summary: Modifications in the set of Coordinate Interchange Standards should address the
following: o Determine if the activities in the Coordinate Interchange standards correctly
identify the responsible entity. o Consider requiring the Sink Balancing Authority responsibility for
Interchange Authority functions, using an interchange transaction tool process as defined in the latest approved version of the e-Tag Specifications.
o The existing requirements are tool-neutral ? consider adding specific references to the e-Tagging process in the requirements
o Consider adding a requirement to have backup capability for use when the interchange transaction tool fails.
o Consider combining requirements into a fewer number of standards so that the resultant set of requirements follows a chronological sequence that is easier to follow.
o Address the directives issued by FERC in Order 693, and the stakeholder comments from the V0 drafting team and the Violation Risk Factors Drafting Team.
o Determine if there is industry-wide support for the Interchange Subcommittee’s Principles and definition supporting dynamic transfers and pseudo-ties, and if there is support, modify the requirements and add definitions accordingly.
Posted Documents: INT-004-3, Dynamic Transfers INT-006-4, Evaluation of Interchange Transactions INT-009-2, Implementation of Interchange INT-010-2, Interchange Initiation and Modification for Reliability INT-011-1, Intra-Balancing Authority Transaction Identification Implementation Plan Supporting Materials:
o Unofficial Comment Form (Word) o Mapping Document o SAR o VRF and VSL justifications
Key Issues: Key Dates: Initial Ballot window open November 4, 2013through 8:00 p.m. ET on
November 13, 2013 Formal 45-day Comment period open through 8:00 p.m. ET on November 13,
2013
RSC October Meeting Item 6.1 RSC Meeting #13-5, Agenda Item 6.1: NERC Currently Posted Projects
Page 5 of 5
Item Name of Project Details 6.1.g Project 2012-05
ATC Revisions (MOD A) – MOD-001-2
Summary: This project responds to the remaining directives in Order 729 as well as
identifying other issues based on operational lessons learned. Based on stakeholder outreach, the MOD A ad hoc group has developed one revised reliability standard that addresses the FERC directives, paragraph 81 candidates, and making the requirements more results-based while consolidating the MOD A standards (MOD-001, MOD-004, MOD-008, MOD-028, MOD-029, and MOD-030) into a single standard covering the reliability-related impact of ATC and AFC calculations.
Posted Documents: MOD-001-2, Modeling, Data, and Analysis — Available Transmission System
Capability Implementation Plan Supporting Materials:
o Unofficial Comment Form (Word) o SAR o Mapping Document o Proposed Timeline for the Formal Development
Key Issues: 1. Need to ensure reliable calculation of Total Transfer Capability (TTC)
and Total Flowgate Capability (TFC) values 2. Need to ensure transparency and communication with the TOP, the RC,
and other registered entities that may have a reliability need to understand how TTC, TFC, TRM, CBM, ATC, and AFC are calculated
3. Need to ensure the sharing of data with other TOPs and TSPs to support their calculations of these values
Key Dates: Additional Ballot window will be conducted from November 8, 2013 through
8:00 p.m. ET on November 18, 2013 Formal 45-day Comment period open through 8:00 p.m. ET on November 18,
2013
RSC October 2013 Meeting Item 6.2 NERC Ballot History (since last RSC Meeting)
Line Project
Link to Ballot Resultshttps://standards.nerc.net/Ballot.aspx
(clicking in the column to the right of “Ballot Periods” column links to the Ballot Results)
Ballot Type Start DateEnd Date
(SortedOldest to Newest)
Ballot Results Recommendation/Date Comments
409 Project 2007‐17.2Project 2007‐17.2 ‐ Protection System Maintenance and Testing ‐ Phase 2 (Reclosing Relays) ‐ PRC‐005‐3
Initial Ballot 8/14/2013 8/23/2013Quorum: 78.33%Approval: 79.42%
Support8/23/13
410 Project 2007‐17.2Project 2007‐17.2 ‐ Protection System Maintenance and Testing ‐ Phase 2 (Reclosing Relays) ‐ PRC‐005‐3
Non‐binding Poll 8/14/2013 8/23/2013Quorum: 77.45%Approval: 81.37%
411 Project 2012‐05 Project 2012‐05 ATC Revisions (MOD A) ‐ MOD‐001‐2 Ballot 8/16/2013 8/26/2013Quorum: 76.14%Approval: 51.10%
No Consensus8/26/13
NPCC to support with comments
412 Project 2012‐05 Project 2012‐05 ATC Revisions (MOD A) ‐ MOD‐001‐2 Non‐binding Poll 8/16/2013 8/26/2013Quorum: 75.98%Approval: 53.29%
413 Project 2010‐01 Project 2010‐01 ‐ Training ‐ PER‐005‐2 Ballot 8/23/2013 9/3/2013Quorum: 75.25%Approval: 34.46%
No Consensus8/31/13
NPCC to support with commentsThe most contentious issues raised by RSC members was surrounding the Control Center definition and the potential to vastly expand those needing training subject to the standard and compliance and that there was no need for a standard, rather, the FERC Directives should be addressed through other means.
414 Project 2010‐01 Project 2010‐01 ‐ Training ‐ PER‐005‐2 Non‐binding Poll 8/23/2013 9/3/2013Quorum: 80.45%Approval: 34.24%
Page 1 of 3
RSC October 2013 Meeting Item 6.2 NERC Ballot History (since last RSC Meeting)
Line Project
Link to Ballot Resultshttps://standards.nerc.net/Ballot.aspx
(clicking in the column to the right of “Ballot Periods” column links to the Ballot Results)
Ballot Type Start DateEnd Date
(SortedOldest to Newest)
Ballot Results Recommendation/Date Comments
415 Project 2013‐04Project 2013‐04 Voltage and Reactive Control ‐ VAR‐001‐4, VAR‐002‐3
Ballot 8/23/2013 9/3/2013Quorum: 81.89%Approval: 43.79%
Oppose8/31/13
The standard, in the view of the group, has extensive issues including but not limited to, applicability issues, lacks clarity, missing measures, quality, and other substantive issues. NPCC will be submitting detailed comments to address these issues. The RSC does not believe it would be beneficial to support the standard at this point as the next step, if it fails the initial ballot, would still require an additional ballot prior to moving to recirculation due to the substantive changes that are needed for the next revision. NPCC will be submitting helpful comments to NERC and supporting the drafting team effort.
416 Project 2013‐04Project 2013‐04 Voltage and Reactive Control ‐ VAR‐001‐4, VAR‐002‐3
Non‐binding Poll 8/23/2013 9/3/2013Quorum: 79.95%Approval: 44.23%
417 Project 2010‐03Project 2010‐03 ‐ Modeling Data (MOD B) ‐ MOD‐032‐1, MOD‐033‐1
Ballot 8/26/2013 9/4/2013Quorum: 82.29%Approval: 41.24%
Support8/31/13
418 Project 2010‐03Project 2010‐03 ‐ Modeling Data (MOD B) ‐ MOD‐032‐1, MOD‐033‐1
Non‐binding Poll 8/26/2013 9/4/2013Quorum: 79.66%Approval: 40.00%
419 Project 2010‐04 Project 2010‐04 ‐ Demand Data (MOD C) ‐ MOD‐031‐1 Ballot 8/26/2013 9/4/2013Quorum: 81.96%Approval: 55.76%
Support8/31/13
420 Project 2010‐04 Project 2010‐04 ‐ Demand Data (MOD C) ‐ MOD‐031‐1 Non‐binding Poll 8/26/2013 9/4/2013Quorum: 80.35%Approval: 58.97%
421 Project 2010‐17Project 2010‐17 ‐ Definition of Bulk Electric System (Phase 2)
Additional Ballot 8/26/2013 9/4/2013Quorum: 78.68%Approval: 66.11%
Support8/31/13
422 Project 2010‐14.1 Project 2010‐14.1 ‐ Phase 1 of Balancing Authority Reliability‐based Controls: Reserves ‐ BAL‐002‐2, BAL‐013‐1
Ballot 9/6/2013 9/16/2013Quorum: 76.15%Approval: 58.23%
No Consensus9/12/13
423 Project 2010‐14.1 Project 2010‐14.1 ‐ Phase 1 of Balancing Authority Reliability‐based Controls: Reserves ‐ BAL‐002‐2, BAL‐013‐1
Non‐binding Poll 9/6/2013 9/16/2013Quorum: 75.69%Approval: 59.66%
424 Project 2012‐INT‐04 Project 2012‐INT‐04 ‐ Interpretation of CIP‐007‐3 for ITC Final Ballot 9/11/2013 9/20/2013Quorum: 91.64%Approval: 98.61%
Support3/14/13
425 Project 2012‐INT‐06Project 2012‐INT‐06 ‐ Interpretation of CIP‐003‐3 for Consumers Energy
Final Ballot 9/11/2013 9/20/2013Quorum: 90.98%Approval: 98.92%
Support3/14/13
Page 2 of 3
RSC October 2013 Meeting Item 6.2 NERC Ballot History (since last RSC Meeting)
Line Project
Link to Ballot Resultshttps://standards.nerc.net/Ballot.aspx
(clicking in the column to the right of “Ballot Periods” column links to the Ballot Results)
Ballot Type Start DateEnd Date
(SortedOldest to Newest)
Ballot Results Recommendation/Date Comments
426 Project 2010‐13.2Project 2010‐13.2 ‐ Phase 2 of Relay Loadability: Generation ‐ PRC‐023 ‐3
Final Ballot 9/4/2013 9/13/2013Quorum: 85.93%Approval: 90.83%
Support8/5/13
427 Project 2013‐03Project 2013‐03 Geomagnetic Disturbance Mitigation ‐ EOP‐010‐1
Additional Ballot 10/9/2013 10/18/2013Quorum: %Approval: %
428 Project 2013‐03Project 2013‐03 Geomagnetic Disturbance Mitigation ‐ EOP‐010‐1
Non‐binding Poll 10/9/2013 10/18/2013Quorum: %Approval: %
429
Page 3 of 3
RSC October 2013 Meeting Item 6.3 RSC Meeting #13-5, Agenda Item 6.3: Comment History
(Since last RSC Meeting)
Page 1 of 2
Line Project# Description Document Comment
Type Start Date End Date NPCC
Submitted
163. Project 2007-17.2
Project 2007-17.2 - Protection System Maintenance and Testing - Phase 2 (Reclosing Relays) - PRC-005
PRC-005-3 Formal 7/10/13 8/23/13 Yes 8/23/13
164. Project 2008-12
Project 2008-12 - Coordinate Interchange Standards - Various INT standards
INT-004-3 INT-006-4 INT-009-2 INT-010-2 INT-011-1
Informal 7/25/13 8/23/13 Yes 8/23/13
165. Project 2012-05
Project 2012-05 ATC Revisions (MOD A) - MOD-001-2
MOD-001-2 Formal 7/11/13 8/26/13 Yes 8/26/13
166. Project 2010-01
Project 2010-01 - Training - PER-005-2
PER-005-2 Formal 7/19/13 9/03/13 Yes 9/3/13
167. Project 2013-04
Project 2013-04 Voltage and Reactive Control - VAR-001-4, VAR-002-3
VAR-001-4 VAR-002-3 Formal 7/19/13 9/03/13 Yes
9/3/13
168 Project 2010-03
Project 2010-03 - Modeling Data (MOD B) - MOD-032-1, MOD-033-1
MOD-032-1 MOD-033-1 Formal 7/22/13 9/04/13 Yes
9/4/13
169. Project 2010-04
Project 2010-04 - Demand Data (MOD C) - MOD-031-1
MOD-031-1 Formal 7/22/13 9/04/13 Yes 9/4/13
170 Project 2010-17
Project 2010-17 - Definition of Bulk Electric System – Phase 2
BES Definition Phase 2 Formal 8/6/13 9/4/13 Yes
9/4/13
171 Project 2012-13
Project 2012-13 - NUC Five-Year Review
NUC-001-2 5-year review 7/26/13 9/9/13 Yes
9/9/13
172 2014-2016 RSDP
2014-2016 Reliability Standards Development Plan
Reliability Standards
Development Plan
Annual Review 8/30/13 9/13/13 Yes
9/13/13
173 Project 2010-02
Project 2010-02 Five-Year Review of FAC Standards
FAC-001-1 FAC-002-1
5-year review 8/1/13 9/16/13 Yes
9/16/13
RSC October 2013 Meeting Item 6.3 RSC Meeting #13-5, Agenda Item 6.3: Comment History
(Since last RSC Meeting)
Page 2 of 2
Line Project# Description Document Comment
Type Start Date End Date NPCC
Submitted
174 Project 2010-02
Project 2010-02 Five-Year Review of FAC Standards
FAC-003-3 FAC-008-3
FAC-010-2.1 FAC-011-2 FAC-013-2 FAC-014-2
5-year review 8/1/13 9/16/13 Yes
9/16/13
175 Project 2010-14.1
Project 2010-14.1 - Phase 1 of Balancing Authority Reliability-based Controls: Reserves - BAL-002-2, BAL-013-1
BAL-002-2 Formal 8/2/13 9/16/13 Yes 9/16/13
176 Project 2009-03
Project 2009-03 ― Five-Year Review of Emergency Operations EOP-001, EOP-002, EOP-003, and IRO-001
EOP-001-2.1b EOP-002-3.1 EOP-003-2
5-year review 8/6/13 9/19/13 Yes
9/19/13
177 Project 2012-09
Project 2012-09 IRO Five-Year Review
IRO-003-2 IRO-004-2 IRO-005-4 IRO-006-5
IRO-006-East IRO-008-1 IRO-009-1 IRO-010-1a
5-year review 8/7/13 9/20/13 Yes
9/20/13
Note: RSC past comment forms are being posted on the NPCC Website under “Standards - Regional Standards Comments.”
Notice of Request to Waive the Standard Process Project 2007-02 Operating Personnel Communications Protocols: COM-003-1 As required by Section 16 of the NERC Standard Processes Manual (SPM), this is official notice to stakeholders that NERC Staff and the Chair of the Standards Committee are requesting that the Standards Committee consider a waiver of the SPM. Specifically, NERC Staff and the Chair of the Standards Committee are requesting that the Standards Committee consider reducing the time for the next successive comment and ballot of a standard combining COM-002 and COM-003 from 45 calendar days to 15 calendar days (with the last 10 days for the ballot) and any final ballot from 10 calendar days to 5 calendar days. The Standards Committee is expected to meet the week of October 7, 2013 to consider this waiver request. The Standards Committee’s meeting will be noticed through an announcement and posted on the NERC website. Additional details about the waiver request are included below. Should a waiver be granted by the Standards Committee, it will be posted on the project page.
Justification for Current Waiver Request
The Board of Trustees resolved at its August 15, 2013 meeting to consider at the upcoming November 7, 2013 meeting how best to act with respect to the disposition of the draft COM-003-1 Reliability Standard, informed, in part, by input received from the Reliability Issues Steering Committee, the Independent Experts Review Panel, NERC management, and the Operating Committee. The Board’s August 15 resolution is available here.
On September 30, 2013, the Board’s Standards Oversight and Technology Committee (SOTC) held a closed conference call to deliberate on the inputs to the Board’s questions received on the draft COM-003-1 Reliability Standard from the Independent Expert Review Panel, Reliability Issues Steering Committee, NERC Management and the Operating Committee. The SOTC approved a recommendation to the Board directing the Standards Committee to work with the COM-003-1 standard drafting team to develop a combined COM-002 and COM-003 standard that includes the essential elements included in the SOTC’s resolution. Prior to Board action, the SOTC further agreed to ask the Standards Committee to expeditiously work with the standard drafting team to produce a draft of and ballot a combined standard before the November 7, 2013 Board meeting. Based on the action of the SOTC, the Standards Committee is requested to approve a new waiver to enable the Project 2007-02 standard drafting team to develop a draft combined standard with the input and direction from the SOTC. This new waiver will
Standards Announcement COM-003-1 Notice of Request to Waive SPM | October 2012 2
supersede the COM-003-1 waiver approved by the Standards Committee at its September 19th meeting. The Standards Committee is also requested to approve a shorter time period for the initial posting to develop, post, and ballot the draft combined standard before the November 7, 2013 Board meeting. The Standards Committee may, under Section 16 of the SPM, approve the waiver of any of the provisions in the SPM for good cause shown, but limited to the following circumstances:
In response to a national emergency declared by the United States or Canadian government that involves the reliability of the Bulk Electric System or cyber attack on the Bulk Electric System;
Where necessary to meet regulatory deadlines;
Where necessary to meet deadlines imposed by the NERC Board of Trustees; or
Where the Standards Committee determines that a modification to a proposed Reliability Standard or its Requirement(s), a modification to a defined term, a modification to an interpretation, or a modification to a variance has already been vetted by the industry through the standards development process or is so insubstantial that developing the modification through the processes contained in this manual will add significant time delay.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process. The success of the NERC standards development process depends on stakeholder participation. NERC extends its thanks to all those who participate.
For more information or assistance, please contact Howard Gugel, Director of Standards Development, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Proposed Waiver on COM-002 and COM-003 Reliability Standards
Action Approve a waiver to shorten ballot and comment periods during development of a combined COM-002 and COM-003 standard.
Background In order to be ready for potential direction from the Board of Trustees (“Board”) regarding COM-003-1, the SC took two actions at its meeting on September 19, 2013 enabling the development of a revised COM-003-1 standard on an expedited timeline. On September 30, 2013, the Board’s Standards Oversight and Technology Committee (“SOTC”) held a closed conference call to deliberate on the inputs to the Board’s questions received on the draft COM-003-1 Reliability Standard from the Independent Expert Review Panel, Reliability Issues Steering Committee, NERC Management and the Operating Committee. The SOTC approved a recommendation to the Board directing the SC to work with the COM-003-1 standard drafting team to develop a combined COM-002 and COM-003 standard (the “combined standard”) that includes essential elements included in the SOTC’s resolution. Prior to Board action, the SOTC further agreed to ask the SC to expeditiously work with the standard drafting team to produce a draft and ballot a combined standard before the November 7, 2013 Board meeting. Based on the action of the SOTC, the SC is requested to approve a new waiver that will supersede the SC’s September 19, 2013 waiver on COM-003 that will allow the COM-003 standard drafting team to approve development of a revised standard on a shortened timeline and will enable the standard drafting team to develop a draft combined standard with the input and direction from the SOTC. The SC is also requested to approve a shorter time period for the initial posting to develop, post, and ballot the draft combined standard before the November 7, 2013 Board meeting. The proposed waiver on a combined COM-002/COM-003 standard is included below:
If, prior to or at its November 7, 2013 meeting, the Board or the Standards Oversight and Technology Committee requests or directs the COM-003-1 standard drafting team to post for comment and ballot a proposed COM-002 and COM-003 standard (the “combined standard”), the Standards Committee approves the following waiver:
a. Direct the COM-003-1 standard drafting team to develop a combined standard and post the revised combined standard for a 15-calendar day comment and concurrent 10-calendar day ballot period.
b. If the revised combined standard passes, the COM-003-1 standard drafting team is directed to post the revised combined standard for a 5-calendar day final ballot period.
c. If the revised combined standard does not pass, the standard drafting team is directed not to post the revised combined standard for final ballot.
RSC October 2013 Meeting Item 6.6
RSC Meeting #13-5, Agenda Item 6.6: Project 2007-17.2 PRC-005-3
Member company feedback:
Standard PRC-005-3 adds maintenance of Auto Reclosing systems. This addition does not seem to be well thought out. The footnote for section 4.2.6 is particularly worrisome as it requires analysis of “…a close-in three-phase fault present for twice the normal clearing time…does not result in total loss of generation in the Interconnection exceeding the largest unit within the BA…”
Why twice the normal clearing time? Why the largest unit in the BA?
If they need to include maintenance of Auto Reclosing systems, then this document needs a lot of work; this draft, and particularly the footnote is very confusing.
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 1
Standard Development Roadmap This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. Standards Committee approved posting SAR and draft standard on January 17, 2013.
2. SAR posted for 30-day informal comment period from April 5, 2013 through May 6, 2013.
3. Draft 1 of PRC-005-3 posted for a 30-day formal comment period from April 5, 2013 through
May 6, 2013.
4. Draft 2 of PRC-005-3 posted for a 45-day formal comment period from July 10, 2013 through
August 23, 2013.
Description of Current Draft:
This is the second draft of the PRC-005-3. The standard modifies PRC-005-2 to address the directive
issued by the Federal Energy Regulatory Commission in Order No.758 for “NERC to include the
maintenance and testing of reclosing relays that can affect the reliable operation of the Bulk-Power
System...”
Future Development Plan:
Anticipated Actions Anticipated Date
1. Post for a concurrent 45-day comment and ballot July 2013
2. Conduct recirculation ballot October 2013
3. BOT Adoption November 2013
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 2
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, the following defined term will be removed from the individual standard and added to the
Glossary.
Protection System Maintenance Program (PSMP) (NERC Board of Trustees Approved Definition) — An ongoing program by which Protection System and automatic reclosing components
are kept in working order and proper operation of malfunctioning components is restored. A maintenance
program for a specific component includes one or more of the following activities:
• Verify — Determine that the component is functioning correctly.
• Monitor — Observe the routine in-service operation of the component.
• Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
• Inspect — Examine for signs of component failure, reduced performance or degradation.
• Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
The following terms are defined for use only within PRC-005-3, and should remain with the standard
upon approval rather than being moved to the Glossary of Terms.
Automatic Reclosing – Includes the following Components:
• Reclosing relay
• Control circuitry associated with the reclosing relay.
Unresolved Maintenance Issue – A deficiency identified during a maintenance activity that causes the
component to not meet the intended performance, cannot be corrected during the maintenance interval, and requires follow-up corrective action.
Segment – Components of a consistent design standard, or a particular model or type from a single
manufacturer that typically share other common elements. Consistent performance is expected across the
entire population of a Segment. A Segment must contain at least sixty (60) individual Components.
Component Type – Either any one of the five specific elements of the Protection System definition or
any one of the two specific elements of the Automatic Reclosing definition.
Component – A Component is any individual discrete piece of equipment included in a Protection
System or in Automatic Reclosing, including but not limited to a protective relay, reclosing relay, or
current sensing device. The designation of what constitutes a control circuit Component is dependent
upon how an entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis. Thus,
entities are allowed the latitude to designate their own definitions of control circuit Components. Another
example of where the entity has some discretion on determining what constitutes a single Component is
the voltage and current sensing devices, where the entity may choose either to designate a full three-phase
set of such devices or a single device as a single Component.
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 3
Countable Event – A failure of a Component requiring repair or replacement, any condition discovered
during the maintenance activities in Tables 1-1 through 1-5, Table 3, and Tables 4-1 through 4-2 which
requires corrective action or a Protection System Misoperation attributed to hardware failure or
calibration failure. Misoperations due to product design errors, software errors, relay settings different
from specified settings, Protection System Component or Automatic Reclosing configuration or
application errors are not included in Countable Events.
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 4
A. Introduction
1. Title: Protection System and Automatic Reclosing Maintenance
2. Number: PRC-005-3
3. Purpose: To document and implement programs for the maintenance of all Protection
Systems and Automatic Reclosing affecting the reliability of the Bulk Electric System (BES)
so that they are kept in working order.
4. Applicability:
4.1. Functional Entities:
4.1.1 Transmission Owner
4.1.2 Generator Owner
4.1.3 Distribution Provider
4.2. Facilities:
4.2.1 Protection Systems that are installed for the purpose of detecting Faults on BES
Elements (lines, buses, transformers, etc.)
4.2.2 Protection Systems used for underfrequency load-shedding systems installed per
ERO underfrequency load-shedding requirements.
4.2.3 Protection Systems used for undervoltage load-shedding systems installed to
prevent system voltage collapse or voltage instability for BES reliability.
4.2.4 Protection Systems installed as a Special Protection System (SPS) for BES
reliability.
4.2.5 Protection Systems for generator Facilities that are part of the BES, including:
4.2.5.1 Protection Systems that act to trip the generator either directly or via lockout
or auxiliary tripping relays.
4.2.5.2 Protection Systems for generator step-up transformers for generators that are
part of the BES.
4.2.5.3 Protection Systems for transformers connecting aggregated generation,
where the aggregated generation is part of the BES (e.g., transformers
connecting facilities such as wind-farms to the BES).
4.2.5.4 Protection Systems for station service or excitation transformers connected to
the generator bus of generators which are part of the BES, that act to trip the
generator either directly or via lockout or tripping auxiliary relays.
4.2.6 Automatic Reclosing1, including:
4.2.6.1 Automatic Reclosing applied on the terminals of Elements connected to the
BES bus located at generating plant substations where the total installed
1 Automatic Reclosing addressed in Section 4.2.6.1 and 4.2.6.2 may be excluded if the equipment owner can
demonstrate that a close-in three-phase fault present for twice the normal clearing time (capturing a minimum trip-
close-trip time delay) does not result in a total loss of gross generation in the Interconnection exceeding the gross
capacity of the largest BES generating unit within the Balancing Authority Area where the Automatic Reclosing is
applied.
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 5
gross generating plant capacity is greater than the gross capacity of the
largest BES generating unit within the Balancing Authority Area.
4.2.6.2 Automatic Reclosing applied on the terminals of all BES Elements at
substations one bus away from generating plants specified in Section 4.2.6.1
when the substation is less than 10 circuit-miles from the generating plant
substation.
4.2.6.3 Automatic Reclosing applied as an integral part of an SPS specified in
Section 4.2.4.
5. Effective Date: See Implementation Plan
B. Requirements
R1. Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a
Protection System Maintenance Program (PSMP) for its Protection Systems and Automatic
Reclosing identified in Facilities Section 4.2. [Violation Risk Factor: Medium] [Time
Horizon: Operations Planning]
The PSMP shall:
1.1. Identify which maintenance method (time-based, performance-based per PRC-005
Attachment A, or a combination) is used to address each Protection System and
Automatic Reclosing Component Type. All batteries associated with the station dc
supply Component Type of a Protection System shall be included in a time-based
program as described in Table 1-4
and Table 3.
1.2. Include the applicable monitored
Component attributes applied to each
Protection System and Automatic
Reclosing Component Type
consistent with the maintenance
intervals specified in Tables 1-1
through 1-5, Table 2, Table 3, and
Table 4-1 through 4-2 where
monitoring is used to extend the
maintenance intervals beyond those
specified for unmonitored Protection
System and Automatic Reclosing
Components.
R2. Each Transmission Owner, Generator
Owner, and Distribution Provider that uses
performance-based maintenance intervals in
its PSMP shall follow the procedure
established in PRC-005 Attachment A to
establish and maintain its performance-
based intervals. [Violation Risk Factor:
Component – A component is any individual
discrete piece of equipment included in a
Protection System or in Automatic Reclosing,
including but not limited to a protective relay,
reclosing relay, or current sensing device.
The designation of what constitutes a control
circuit component is very dependent upon how
an entity performs and tracks the testing of the
control circuitry. Some entities test their
control circuits on a breaker basis whereas
others test their circuitry on a local zone of
protection basis. Thus, entities are allowed
the latitude to designate their own definitions
of control circuit components. Another
example of where the entity has some
discretion on determining what constitutes a
single component is the voltage and current
sensing devices, where the entity may choose
either to designate a full three-phase set of
such devices or a single device as a single
component.
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 6
Medium] [Time Horizon: Operations Planning]
R3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes time-
based maintenance program(s) shall maintain its Protection System and Automatic Reclosing
Components that are included within the time-based maintenance program in accordance with
the minimum maintenance activities and maximum maintenance intervals prescribed within
Tables 1-1 through 1-5, Table 2, Table 3, and Table 4-1 through 4-2. [Violation Risk Factor:
High] [Time Horizon: Operations Planning]
R4. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
performance-based maintenance program(s) in accordance with Requirement R2 shall
implement and follow its PSMP for its Protection System and Automatic Reclosing
Components that are included within the performance-based program(s). [Violation Risk
Factor: High] [Time Horizon: Operations Planning]
R5. Each Transmission Owner, Generator Owner, and Distribution Provider shall demonstrate
efforts to correct identified Unresolved Maintenance Issues. [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning]
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 7
C. Measures
M1. Each Transmission Owner, Generator Owner and Distribution Provider shall have a
documented Protection System Maintenance Program in accordance with Requirement R1.
For each Protection System and Automatic Reclosing Component Type, the documentation
shall include the type of maintenance method applied (time-based, performance-based, or a
combination of these maintenance methods), and shall include all batteries associated with the
station dc supply Component Types in a time-based program as described in Table 1-4 and
Table 3. (Part 1.1)
For Component Types that use monitoring to extend the maintenance intervals, the responsible
entity(s) shall have evidence for each Protection System and Automatic Reclosing Component
Type (such as manufacturer’s specifications or engineering drawings) of the appropriate
monitored Component attributes as specified in Tables 1-1 through 1-5, Table 2, Table 3, and
Table 4-1 through 4-2. (Part 1.2)
M2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses performance-
based maintenance intervals shall have evidence that its current performance-based
maintenance program(s) is in accordance with Requirement R2, which may include but is not
limited to Component lists, dated maintenance records, and dated analysis records and results.
M3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes time-
based maintenance program(s) shall have evidence that it has maintained its Protection System
and Automatic Reclosing Components included within its time-based program in accordance
with Requirement R3. The evidence may include but is not limited to dated maintenance
records, dated maintenance summaries, dated check-off lists, dated inspection records, or dated
work orders.
M4. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
performance-based maintenance intervals in accordance with Requirement R2 shall have
evidence that it has implemented the Protection System Maintenance Program for the
Protection System and Automatic Reclosing Components included in its performance-based
program in accordance with Requirement R4. The evidence may include but is not limited to
dated maintenance records, dated maintenance summaries, dated check-off lists, dated
inspection records, or dated work orders.
M5. Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
that it has undertaken efforts to correct identified Unresolved Maintenance Issues in
accordance with Requirement R5. The evidence may include but is not limited to work orders,
replacement Component orders, invoices, project schedules with completed milestones, return
material authorizations (RMAs) or purchase orders.
D. Compliance
1. Compliance Monitoring Process
1.1. 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.
1.2. Compliance Monitoring and Enforcement Processes:
Compliance Audit
Self-Certification
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 8
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
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.
The Transmission Owner, Generator Owner, and Distribution Provider shall each 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.
For Requirement R1, the Transmission Owner, Generator Owner, and Distribution
Provider shall each keep its current dated Protection System Maintenance Program, as
well as any superseded versions since the preceding compliance audit, including the
documentation that specifies the type of maintenance program applied for each Protection
System Component Type.
For Requirement R2, Requirement R3, Requirement R4, and Requirement R5, the
Transmission Owner, Generator Owner, and Distribution Provider shall each keep
documentation of the two most recent performances of each distinct maintenance activity
for the Protection System or Automatic Reclosing Component, or all performances of
each distinct maintenance activity for the Protection System or Automatic Reclosing
Component since the previous scheduled audit date, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None.
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 9
2. Violation Severity Levels
Requirement Number
Lower VSL Moderate VSL High VSL Severe VSL
R1 The responsible entity’s PSMP failed
to specify whether one Component
Type is being addressed by time-
based or performance-based
maintenance, or a combination of
both. (Part 1.1)
OR
The responsible entity’s PSMP failed
to include applicable station batteries
in a time-based program. (Part 1.1)
The responsible entity’s PSMP
failed to specify whether two
Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1)
The responsible entity’s PSMP
failed to specify whether three
Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1).
OR
The responsible entity’s PSMP
failed to include the applicable
monitoring attributes applied to each
Component Type consistent with the
maintenance intervals specified in
Tables 1-1 through 1-5, Table 2,
Table 3, and Tables 4-1 through 4-2
where monitoring is used to extend
the maintenance intervals beyond
those specified for unmonitored
Components. (Part 1.2).
The responsible entity failed to
establish a PSMP.
OR
The responsible entity’s PSMP
failed to specify whether four or
more Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1).
R2 The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no more
than 4% within three years.
NA The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no more
than 4% within four years.
The responsible entity uses
performance-based maintenance
intervals in its PSMP but:
1) Failed to establish the technical
justification described within
Requirement R2 for the initial
use of the performance-based
PSMP
OR
2) Failed to reduce Countable
Events to no more than 4%
within five years
OR
3) Maintained a Segment with
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 10
Requirement Number
Lower VSL Moderate VSL High VSL Severe VSL
less than 60 Components
OR
4) Failed to:
• Annually update the list of
Components,
OR
• Annually perform
maintenance on the greater
of 5% of the Segment
population or 3
Components,
OR
• Annually analyze the
program activities and
results for each Segment.
R3 For Components included within a
time-based maintenance program, the
responsible entity failed to maintain
5% or less of the total Components
included within a specific
Component Type, in accordance with
the minimum maintenance activities
and maximum maintenance intervals
prescribed within Tables 1-1 through
1-5, Table 2, Table 3, and Tables 4-1
through 4-2.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 5% but 10% or
less of the total Components
included within a specific
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5,
Table 2, Table 3, and Tables 4-1
through 4-2.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 10% but 15% or
less of the total Components
included within a specific
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5, Table
2, Table 3, and Tables 4-1 through
4-2.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 15% of the total
Components included within a
specific Component Type, in
accordance with the minimum
maintenance activities and
maximum maintenance intervals
prescribed within Tables 1-1
through 1-5, Table 2, Table 3, and
Tables 4-1 through 4-2.
R4 For Components included within a
performance-based maintenance
program, the responsible entity failed
to maintain 5% or less of the annual
scheduled maintenance for a specific
Component Type in accordance with
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 5% but
10% or less of the annual scheduled
maintenance for a specific
Component Type in accordance
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 10%
but 15% or less of the annual
scheduled maintenance for a specific
Component Type in accordance with
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 15%
of the annual scheduled
maintenance for a specific
Component Type in accordance
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 11
Requirement Number
Lower VSL Moderate VSL High VSL Severe VSL
their performance-based PSMP. with their performance-based
PSMP.
their performance-based PSMP. with their performance-based
PSMP.
R5 The responsible entity failed to
undertake efforts to correct 5 or
fewer identified Unresolved
Maintenance Issues.
The responsible entity failed to
undertake efforts to correct greater
than 5, but less than or equal to 10
identified Unresolved Maintenance
Issues.
The responsible entity failed to
undertake efforts to correct greater
than 10, but less than or equal to 15
identified Unresolved Maintenance
Issues.
The responsible entity failed to
undertake efforts to correct greater
than 15 identified Unresolved
Maintenance Issues.
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 12
E. Regional Variances
None
F. Supplemental Reference Document
The following documents present a detailed discussion about determination of maintenance intervals
and other useful information regarding establishment of a maintenance program.
1. PRC-005-2 Protection System Maintenance Supplementary Reference and FAQ — March 2013.
2. Considerations for Maintenance and Testing of Autoreclosing Schemes — November 2012.
Version History
Version Date Action Change Tracking
0 April 1, 2005 Effective Date New
1 December 1,
2005
1. Changed incorrect use of certain
hyphens (-) to “en dash” (–) and “em
dash (—).”
2. Added “periods” to items where
appropriate.
3. Changed “Timeframe” to “Time Frame”
in item D, 1.2.
01/20/05
1a February 17,
2011
Added Appendix 1 - Interpretation
regarding applicability of standard to
protection of radially connected
transformers
Project 2009-17
interpretation
1a February 17,
2011
Adopted by Board of Trustees
1a September 26,
2011
FERC Order issued approving interpretation
of R1 and R2 (FERC’s Order is effective as
of September 26, 2011)
1.1a February 1,
2012
Errata change: Clarified inclusion of
generator interconnection Facility in
Generator Owner’s responsibility
Revision under Project
2010-07
1b February 3,
2012
FERC Order issued approving interpretation
of R1, R1.1, and R1.2 (FERC’s Order dated
March 14, 2012). Updated version from 1a
to 1b.
Project 2009-10
Interpretation
1.1b April 23, 2012 Updated standard version to 1.1b to reflect
FERC approval of PRC-005-1b.
Revision under Project
2010-07
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 13
1.1b May 9, 2012 PRC-005-1.1b was adopted by the Board of
Trustees as part of Project 2010-07
(GOTO).
2 November 7,
2012
Adopted by Board of Trustees Project 2007-17 -
Complete revision,
absorbing maintenance
requirements from PRC-
005-1.1b, PRC-008-0,
PRC-011-0, PRC-017-0
3 TBD Revised to include Automatic Reclosing in
maintenance programs Project 2007-17.2
Revision to address the
FERC directive in Order
No.758 regarding
Automatic Reclosing
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 14
Table 1-1 Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes Maximum
Maintenance Interval2
Maintenance Activities
Any unmonitored protective relay not having all the monitoring attributes
of a category below.
6 Calendar
Years
For all unmonitored relays:
• Verify that settings are as specified
For non-microprocessor relays:
• Test and, if necessary calibrate
For microprocessor relays:
• Verify operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System.
• Verify acceptable measurement of power system input values.
Monitored microprocessor protective relay with the following:
• Internal self-diagnosis and alarming (see Table 2).
• Voltage and/or current waveform sampling three or more times per
power cycle, and conversion of samples to numeric values for
measurement calculations by microprocessor electronics.
• Alarming for power supply failure (see Table 2).
12 Calendar
Years
Verify:
• Settings are as specified.
• Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
• Acceptable measurement of power system input values.
2 For the tables in this standard, a calendar year starts on the first day of a new year (January 1) after a maintenance activity has been completed.
For the tables in this standard, a calendar month starts on the first day of the first month after a maintenance activity has been completed.
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 15
Table 1-1 Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes Maximum
Maintenance Interval2
Maintenance Activities
Monitored microprocessor protective relay with preceding row attributes
and the following:
• Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive error
(See Table 2).
• Some or all binary or status inputs and control outputs are monitored
by a process that continuously demonstrates ability to perform as
designed, with alarming for failure (See Table 2).
• Alarming for change of settings (See Table 2).
12 Calendar
Years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 16
Table 1-2 Component Type - Communications Systems
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes Maximum
Maintenance Interval
Maintenance Activities
Any unmonitored communications system necessary for correct operation of
protective functions, and not having all the monitoring attributes of a category
below.
4 Calendar
Months Verify that the communications system is functional.
6 Calendar
Years
Verify that the communications system meets performance
criteria pertinent to the communications technology applied (e.g.
signal level, reflected power, or data error rate).
Verify operation of communications system inputs and outputs
that are essential to proper functioning of the Protection System.
Any communications system with continuous monitoring or periodic
automated testing for the presence of the channel function, and alarming for
loss of function (See Table 2).
12 Calendar
Years
Verify that the communications system meets performance
criteria pertinent to the communications technology applied (e.g.
signal level, reflected power, or data error rate).
Verify operation of communications system inputs and outputs
that are essential to proper functioning of the Protection System.
Any communications system with all of the following:
• Continuous monitoring or periodic automated testing for the performance
of the channel using criteria pertinent to the communications technology
applied (e.g. signal level, reflected power, or data error rate, and alarming
for excessive performance degradation). (See Table 2)
• Some or all binary or status inputs and control outputs are monitored by a
process that continuously demonstrates ability to perform as designed,
with alarming for failure (See Table 2).
12 Calendar
Years
Verify only the unmonitored communications system inputs and
outputs that are essential to proper functioning of the Protection
System
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 17
Table 1-3 Component Type - Voltage and Current Sensing Devices Providing Inputs to Protective Relays
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes Maximum
Maintenance Interval
Maintenance Activities
Any voltage and current sensing devices not having monitoring
attributes of the category below. 12 Calendar Years
Verify that current and voltage signal values are provided to the
protective relays.
Voltage and Current Sensing devices connected to microprocessor
relays with AC measurements are continuously verified by comparison
of sensing input value, as measured by the microprocessor relay, to an
independent ac measurement source, with alarming for unacceptable
error or failure (see Table 2).
No periodic
maintenance
specified
None.
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 18
Table 1-4(a) Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or non-distributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes Maximum
Maintenance Interval
Maintenance Activities
Protection System Station dc supply using Vented Lead-Acid
(VLA) batteries not having monitoring attributes of Table 1-
4(f).
4 Calendar Months
Verify:
• Station dc supply voltage
Inspect:
• Electrolyte level
• For unintentional grounds
18 Calendar
Months
Verify:
• Float voltage of battery charger
• Battery continuity
• Battery terminal connection resistance
• Battery intercell or unit-to-unit connection resistance
Inspect:
• Cell condition of all individual battery cells where cells are visible –
or measure battery cell/unit internal ohmic values where the cells are
not visible
• Physical condition of battery rack
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 19
Table 1-4(a) Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or non-distributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes Maximum
Maintenance Interval
Maintenance Activities
18 Calendar
Months
-or-
6 Calendar Years
Verify that the station battery can perform as manufactured by
evaluating cell/unit measurements indicative of battery performance
(e.g. internal ohmic values or float current) against the station battery
baseline.
-or-
Verify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 20
Table 1-4(b) Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or non-distributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes Maximum
Maintenance Interval
Maintenance Activities
Protection System Station dc supply with Valve Regulated
Lead-Acid (VRLA) batteries not having monitoring attributes
of Table 1-4(f).
4 Calendar Months
Verify:
• Station dc supply voltage
Inspect:
• For unintentional grounds
6 Calendar Months
Inspect:
• Condition of all individual units by measuring battery cell/unit
internal ohmic values.
18 Calendar
Months
Verify:
• Float voltage of battery charger
• Battery continuity
• Battery terminal connection resistance
• Battery intercell or unit-to-unit connection resistance
Inspect:
• Physical condition of battery rack
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 21
Table 1-4(b) Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or non-distributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes Maximum
Maintenance Interval
Maintenance Activities
6 Calendar Months
-or-
3 Calendar Years
Verify that the station battery can perform as manufactured by
evaluating cell/unit measurements indicative of battery performance
(e.g. internal ohmic values or float current) against the station battery
baseline.
-or-
Verify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 22
Table 1-4(c) Component Type – Protection System Station dc Supply Using Nickel-Cadmium (NiCad) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS system, or non-distributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes Maximum
Maintenance Interval
Maintenance Activities
Protection System Station dc supply Nickel-Cadmium
(NiCad) batteries not having monitoring attributes of Table 1-
4(f).
4 Calendar Months
Verify:
• Station dc supply voltage
Inspect:
• Electrolyte level
• For unintentional grounds
18 Calendar
Months
Verify:
• Float voltage of battery charger
• Battery continuity
• Battery terminal connection resistance
• Battery intercell or unit-to-unit connection resistance
Inspect:
• Cell condition of all individual battery cells.
• Physical condition of battery rack
6 Calendar Years Verify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 23
Table 1-4(d) Component Type – Protection System Station dc Supply Using Non Battery Based Energy Storage
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS system, or non-distributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes Maximum
Maintenance Interval
Maintenance Activities
Any Protection System station dc supply not using a battery
and not having monitoring attributes of Table 1-4(f).
4 Calendar Months
Verify:
• Station dc supply voltage
Inspect:
• For unintentional grounds
18 Calendar Months Inspect:
Condition of non-battery based dc supply
6 Calendar Years Verify that the dc supply can perform as manufactured when ac power is
not present.
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 24
Table 1-4(e) Component Type – Protection System Station dc Supply for non-BES Interrupting Devices for SPS, non-distributed UFLS, and non-
distributed UVLS systems
Component Attributes Maximum
Maintenance Interval
Maintenance Activities
Any Protection System dc supply used for tripping only non-
BES interrupting devices as part of a SPS, non-distributed
UFLS, or non-distributed UVLS system and not having
monitoring attributes of Table 1-4(f).
When control
circuits are verified
(See Table 1-5) Verify Station dc supply voltage.
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 25
Table 1-4(f) Exclusions for Protection System Station dc Supply Monitoring Devices and Systems
Component Attributes Maximum Maintenance
Interval Maintenance Activities
Any station dc supply with high and low voltage monitoring
and alarming of the battery charger voltage to detect charger
overvoltage and charger failure (See Table 2).
No periodic maintenance
specified
No periodic verification of station dc supply voltage is
required.
Any battery based station dc supply with electrolyte level
monitoring and alarming in every cell (See Table 2).
No periodic inspection of the electrolyte level for each cell is
required.
Any station dc supply with unintentional dc ground monitoring
and alarming (See Table 2).
No periodic inspection of unintentional dc grounds is
required.
Any station dc supply with charger float voltage monitoring
and alarming to ensure correct float voltage is being applied on
the station dc supply (See Table 2).
No periodic verification of float voltage of battery charger is
required.
Any battery based station dc supply with monitoring and
alarming of battery string continuity (See Table 2). No periodic verification of the battery continuity is required.
Any battery based station dc supply with monitoring and
alarming of the intercell and/or terminal connection detail
resistance of the entire battery (See Table 2).
No periodic verification of the intercell and terminal
connection resistance is required.
Any Valve Regulated Lead-Acid (VRLA) or Vented Lead-
Acid (VLA) station battery with internal ohmic value or float
current monitoring and alarming, and evaluating present values
relative to baseline internal ohmic values for every cell/unit
(See Table 2).
No periodic evaluation relative to baseline of battery cell/unit
measurements indicative of battery performance is required to
verify the station battery can perform as manufactured.
Any Valve Regulated Lead-Acid (VRLA) or Vented Lead-
Acid (VLA) station battery with monitoring and alarming of
each cell/unit internal ohmic value (See Table 2).
No periodic inspection of the condition of all individual units
by measuring battery cell/unit internal ohmic values of a
station VRLA or Vented Lead-Acid (VLA) battery is
required.
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 26
Table 1-5 Component Type - Control Circuitry Associated With Protective Functions
Excluding distributed UFLS and distributed UVLS (see Table 3)
Note: Table requirements apply to all Control Circuitry Components of Protection Systems, and SPSs except as noted.
Component Attributes Maximum
Maintenance Interval
Maintenance Activities
Trip coils or actuators of circuit breakers, interrupting devices, or mitigating
devices (regardless of any monitoring of the control circuitry).
6 Calendar
Years
Verify that each trip coil is able to operate the circuit
breaker, interrupting device, or mitigating device.
Electromechanical lockout devices which are directly in a trip path from the
protective relay to the interrupting device trip coil (regardless of any
monitoring of the control circuitry).
6 Calendar
Years
Verify electrical operation of electromechanical lockout
devices.
Unmonitored control circuitry associated with SPS.
(See Table 4-2(b) for SPS which include Automatic Reclosing.)
12 Calendar
Years
Verify all paths of the control circuits essential for proper
operation of the SPS.
Unmonitored control circuitry associated with protective functions inclusive of
all auxiliary relays.
12 Calendar
Years
Verify all paths of the trip circuits inclusive of all auxiliary
relays through the trip coil(s) of the circuit breakers or other
interrupting devices.
Control circuitry associated with protective functions and/or SPSs whose
integrity is monitored and alarmed (See Table 2).
No periodic
maintenance
specified
None.
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 27
Table 2 – Alarming Paths and Monitoring
In Tables 1-1 through 1-5, Table 3, and Tables 4-1 through 4-2, alarm attributes used to justify extended maximum maintenance intervals and/or reduced maintenance activities are subject to the following maintenance requirements
Component Attributes Maximum
Maintenance Interval
Maintenance Activities
Any alarm path through which alarms in Tables 1-1 through 1-5, Table 3, and
Tables 4-1 through 4-2 are conveyed from the alarm origin to the location where
corrective action can be initiated, and not having all the attributes of the “Alarm
Path with monitoring” category below.
Alarms are reported within 24 hours of detection to a location where corrective
action can be initiated.
12 Calendar Years Verify that the alarm path conveys alarm signals to
a location where corrective action can be initiated.
Alarm Path with monitoring:
The location where corrective action is taken receives an alarm within 24 hours
for failure of any portion of the alarming path from the alarm origin to the
location where corrective action can be initiated.
No periodic
maintenance
specified
None.
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 28
Table 3 Maintenance Activities and Intervals for distributed UFLS and distributed UVLS Systems
Component Attributes Maximum
Maintenance Interval
Maintenance Activities
Any unmonitored protective relay not having all the monitoring attributes of a
category below.
6 Calendar
Years
Verify that settings are as specified.
For non-microprocessor relays:
• Test and, if necessary calibrate.
For microprocessor relays:
• Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
• Verify acceptable measurement of power system input
values.
Monitored microprocessor protective relay with the following:
• Internal self diagnosis and alarming (See Table 2).
• Voltage and/or current waveform sampling three or more times per power
cycle, and conversion of samples to numeric values for measurement
calculations by microprocessor electronics.
Alarming for power supply failure (See Table 2).
12 Calendar
Years
Verify:
• Settings are as specified.
• Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
• Acceptable measurement of power system input values
Monitored microprocessor protective relay with preceding row attributes and
the following:
• Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive error
(See Table 2).
• Some or all binary or status inputs and control outputs are monitored by a
process that continuously demonstrates ability to perform as designed,
with alarming for failure (See Table 2).
Alarming for change of settings (See Table 2).
12 Calendar
Years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 29
Table 3 Maintenance Activities and Intervals for distributed UFLS and distributed UVLS Systems
Component Attributes Maximum
Maintenance Interval
Maintenance Activities
Voltage and/or current sensing devices associated with UFLS or UVLS
systems.
12 Calendar
Years
Verify that current and/or voltage signal values are provided to
the protective relays.
Protection System dc supply for tripping non-BES interrupting devices used
only for a UFLS or UVLS system.
12 Calendar
Years Verify Protection System dc supply voltage.
Control circuitry between the UFLS or UVLS relays and electromechanical
lockout and/or tripping auxiliary devices (excludes non-BES interrupting
device trip coils).
12 Calendar
Years Verify the path from the relay to the lockout and/or tripping
auxiliary relay (including essential supervisory logic).
Electromechanical lockout and/or tripping auxiliary devices associated only
with UFLS or UVLS systems (excludes non-BES interrupting device trip
coils).
12 Calendar
Years Verify electrical operation of electromechanical lockout and/or
tripping auxiliary devices.
Control circuitry between the electromechanical lockout and/or tripping
auxiliary devices and the non-BES interrupting devices in UFLS or UVLS
systems, or between UFLS or UVLS relays (with no interposing
electromechanical lockout or auxiliary device) and the non-BES interrupting
devices (excludes non-BES interrupting device trip coils).
No periodic
maintenance
specified None.
Trip coils of non-BES interrupting devices in UFLS or UVLS systems.
No periodic
maintenance
specified None.
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 30
Table 4-1 Maintenance Activities and Intervals for Automatic Reclosing Components
Component Type – Reclosing Relay
Component Attributes Maximum
Maintenance Interval
Maintenance Activities
Any unmonitored reclosing relay not having all the monitoring attributes of a
category below.
6 Calendar
Years
Verify that settings are as specified.
For non-microprocessor relays:
• Test and, if necessary calibrate
For microprocessor relays:
• Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Automatic Reclosing.
Monitored microprocessor reclosing relay with the following:
• Internal self diagnosis and alarming (See Table 2).
• Alarming for power supply failure (See Table 2).
12 Calendar
Years
Verify:
• Settings are as specified.
• Operation of the relay inputs and outputs that are essential to
proper functioning of the Automatic Reclosing.
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 31
Table 4-2(a) Maintenance Activities and Intervals for Automatic Reclosing Components
Component Type – Control Circuitry Associated with Reclosing Relays that are NOT an Integral Part of an SPS
Component Attributes Maximum
Maintenance Interval
Maintenance Activities
Unmonitored Control circuitry associated with Automatic Reclosing that is
not an integral part of an SPS.
12 Calendar
Years
Verify that Automatic Reclosing, upon initiation, does not
issue a premature closing command to the close circuitry.
Control circuitry associated with Automatic Reclosing that is not part of an
SPS and is monitored and alarmed for conditions that would result in a
premature closing command. (See Table 2)
No periodic
maintenance
specified
None.
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 32
Table 4-2(b) Maintenance Activities and Intervals for Automatic Reclosing Components
Component Type – Control Circuitry Associated with Reclosing Relays that ARE an Integral Part of an SPS
Component Attributes Maximum
Maintenance Interval
Maintenance Activities
Close coils or actuators of circuit breakers or similar devices that are used in
conjunction with Automatic Reclosing as part of an SPS (regardless of any
monitoring of the control circuitry).
6 Calendar
Years
Verify that each close coil or actuator is able to operate the
circuit breaker or mitigating device.
Unmonitored close control circuitry associated with Automatic Reclosing
used as an integral part of an SPS.
12 Calendar
Years
Verify all paths of the control circuits associated with Automatic
Reclosing that are essential for proper operation of the SPS.
Control circuitry associated with Automatic Reclosing that is an integral part
of an SPS whose integrity is monitored and alarmed. (See Table 2)
No periodic
maintenance
specified
None.
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 33
PRC-005 — Attachment A
Criteria for a Performance-Based Protection System Maintenance Program
Purpose: To establish a technical basis for initial and continued use of a performance-based
Protection System Maintenance Program (PSMP).
To establish the technical justification for the initial use of a performance-based PSMP:
1. Develop a list with a description of
Components included in each designated
Segment, with a minimum Segment
population of 60 Components.
2. Maintain the Components in each
Segment according to the time-based
maximum allowable intervals established
in Tables 1-1 through 1-5, Table 3, and
Tables 4-1 through 4-2 until results of
maintenance activities for the Segment are available for a minimum of 30 individual
Components of the Segment.
3. Document the maintenance program
activities and results for each Segment,
including maintenance dates and
Countable Events for each included
Component.
4. Analyze the maintenance program
activities and results for each Segment to
determine the overall performance of the
Segment and develop maintenance
intervals.
5. Determine the maximum allowable
maintenance interval for each Segment
such that the Segment experiences
Countable Events on no more than 4% of the Components within the Segment, for the
greater of either the last 30 Components maintained or all Components maintained in the
previous year.
To maintain the technical justification for the ongoing use of a performance-based PSMP:
1. At least annually, update the list of Components and Segments and/or description if any
changes occur within the Segment.
2. Perform maintenance on the greater of 5% of the Components (addressed in the
performance based PSMP) in each Segment or 3 individual Components within the
Segment in each year.
3. For the prior year, analyze the maintenance program activities and results for each
Segment to determine the overall performance of the Segment.
Countable Event – A failure of a component
requiring repair or replacement, any condition
discovered during the maintenance activities in
Tables 1-1 through 1-5, Table 3, and Tables 4-1
through 4-2 which requires corrective action, or a
Protection System Misoperation attributed to
hardware failure or calibration failure.
Misoperations due to product design errors,
software errors, relay settings different from
specified settings, Protection System Component
or Automatic Reclosing configuration or
application errors are not included in Countable
Events.
Segment – Components of a consistent design
standard, or a particular model or type from a
single manufacturer that typically share other
common elements. Consistent performance is
expected across the entire population of a
Segment. A Segment must contain at least sixty
(60) individual Components.
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Draft 2: July, 2013 34
4. Using the prior year’s data, determine the maximum allowable maintenance interval for
each Segment such that the Segment experiences Countable Events on no more than 4%
of the Components within the Segment, for the greater of either the last 30 Components
maintained or all Components maintained in the previous year.
5. If the Components in a Segment maintained through a performance-based PSMP
experience 4% or more Countable Events, develop, document, and implement an action
plan to reduce the Countable Events to less than 4% of the Segment population within 3
years.
RSC October 2013 Meeting Item 7.0 RSC Meeting #13-5, Agenda Item 7.0: NERC Drafting Team Nominations
Page 1 of 1
7.1 Currently Posted Drafting Team Vacancies
Item Name of Project Nominee Qualifications Reply Date:
7.1.a
7.2 Closed Drafting Team Nominations (Since last RSC Meeting)
Item Name of Project Nominee Qualifications Reply Date:
7.2f
7.3 Solicitation For Informal Development Teams
Item Name of Project Nominee Qualifications Reply Date:
7.3.a
RSC October 2013 Meeting Item 8.0
RSC Meeting #13-5, Agenda Item 8.0: Current Activities: Regional Standards
Page 1 of 1
8.1 Current Activities: Regional Standards Item Standard Details 8.1.a PRC-002-NPCC-2 Review PRC-002-NPCC-1 as necessary with due consideration to the revised BES
definition as filed with FERC and revise PRC-002-NPCC-1 accordingly to ensure that sufficient DM equipment is installed to measure and record disturbances on the BES. In addition all NPCC BOD approved interpretations as applicable to the standard will be incorporated into the revised standard. Consideration to all applicable NPCC Compliance Guidance Statements regarding applicability will be reflected in the revision as well as review and potential revision to the Implementation Plan. Status: Regional Standard Authorization Request (RSAR) has been submitted and
approved Drafting Team Nomination period ended March 25, 2013 Draft Team kick-off conference call was Monday April 8, 2013 Project is ongoing
8.2 Current Activities: Regional Standard Interpretations Item Standard Details 8.2.a PRC-002-NPCC-1 Task Force on System Protection (TFSP) has reviewed the following request for
clarification by NAES Corporation-Kleen Energy Systems, LLC. “I would like to request a clarification of R16.1 which states that data files shall be capable of being viewed, read, and analyzed with a generic COMTRADE analysis tool as per the latest revision of IEEE Standard C37.111. As discussed I think R16.1 is more specific to the oscillography data which would likely have a combination of analog and binary data embedded in a data file which could be used to analyze an event. Many fault recorders and protective relays also provide a separate event file which is simply a binary indication of which function operated with an associated time stamp. I think this data should be allowed to be transferred to NPCC in common formats such as .txt, .csv, or .xls since this information has no real value in a COMTRADE analysis tool without the accompanying analog data. If an entity was to be under the 50MVA threshold which would require fault recording capability it could be said that they would only need to provide SOE data in the event of a disturbance. In this case I think it would be reasonable to state that the event data (SOE) they would provide would only need to be compatible with standard formats (.txt, .csv, or .xls)” A response by TFSP to NAES Corporation-Kleen Energy Systems, LLC’s request is provided below. Status: TFSP agrees that R16.1 is applicable to Digital Fault Recording (DFR) and
Dynamic Disturbance Recording (DDR) data in regards to the COMTRADE data format. It would be sufficient to provide Sequence of Event (SOE) recording data in a commonly used format such as txt, csv, or xls.
TFSP response shall be reviewed by the RSC and posted on the NPCC website, as appropriate
October 4, 2013 Mr. Guy Zito NPCC Assistant Vice President-Standards Re: TFSP Response to Request for Clarification by NAES Corporation-Kleen Energy Systems, LLC: PRC-002-NPCC-1, Requirement R16.1 Dear Mr. Zito: As per Mr. Pedowicz’s September 17, 2013 email message to the NPCC Task Force on System Protection (TFSP) and in accordance with the NPCC’s Regional Reliability Standard Development Procedure, the Task Force on System Protection has reviewed the following request for clarification by NAES Corporation-Kleen Energy Systems, LLC.
“I would like to request a clarification of R16.1 which states that data files shall be capable of being viewed, read, and analyzed with a generic COMTRADE analysis tool as per the latest revision of IEEE Standard C37.111. As discussed I think R16.1 is more specific to the oscillography data which would likely have a combination of analog and binary data embedded in a data file which could be used to analyze an event. Many fault recorders and protective relays also provide a separate event file which is simply a binary indication of which function operated with an associated time stamp. I think this data should be allowed to be transferred to NPCC in common formats such as .txt, .csv, or .xls since this information has no real value in a COMTRADE analysis tool without the accompanying analog data. If an entity was to be under the 50MVA threshold which would require fault recording capability it could be said that they would only need to provide SOE data in the event of a disturbance. In this case I think it would be reasonable to state that the event data (SOE) they would provide would only need to be compatible with standard formats (.txt, .csv, or .xls)”
A response by TFSP to NAES Corporation-Kleen Energy Systems, LLC’s request is provided below.
TFSP agrees that R16.1 is applicable to Digital Fault Recording (DFR) and Dynamic Disturbance Recording (DDR) data in regards to the COMTRADE data format. It would be sufficient to provide Sequence of Event (SOE) recording data in a commonly used format such as txt, csv, or xls.
Let me know if you need further assistance on this matter. Sincerely,
Paul Paul DiFilippo, Chairman Task Force on System Protection cc: Members, Task Force on System Protection Mr. Lee Pedowicz – NPCC Regional Standard Process Manager
Mr. Philip Fedora - Assistant Vice President of Reliability Services
RSC October 2013 Meeting Item 9.0 RSC Meeting #13-5, Agenda Item 9.0: NPCC Non-Standards
Page 1 of 1
9.1 Directories In Development Item Directory Details 9.1.a Directory#1 Design
and Operation of the BPS
Status: CP11 and CO7 collaborative review of the Directory #1 Planning and Operating Criteria. Draft of Directory#1with CO7/CP11 proposed revisions placed on the mid –October meeting agendas of the TFCP and TFCO in order to obtain Task Force approval to post the document in the Open Process.
9.1.b Directory#3 Maintenance Criteria for Bulk Power System Protection
Status: TFSP to identify differences/gaps between Directory #3 and the NERC BOT approved PRC-005-2. Pending completion of the TFSP review of Directory#4 in the 4th Quarter of 2013.
9.1.c Directory#4 NPCC Bulk Power System Protection Criteria
Status: TFSP currently performing triennial review; expected completion 4th Quarter 2013.
9.2 Directory Interpretations Item Directory Details 9.2.a
9.3 Criteria (A) / Guides (B) / Procedures (C) Documents Item Document Details 9.3.a A-15 - Disturbance
Monitoring Equipment Criteria
TFSP Document Review Tracking - Consideration for retiring this document is pending full implementation and regulatory approval of PRC-002-NPCC-01.
9.3.b B-25 Guide to Time Synchronization of Substation Equipment
TFSP Document Review Tracking - Consider submitting to RCC draft revised B-25 developed in 2010 Open Process Review – Pending approvals of PRC-002-NPCC-01 in Canadian provinces
9.3.c B-26 Guide for Application of Disturbance Recording Equipment
TFSP Document Review Tracking - Consider submitting to RCC draft revised B-26 developed in 2010 Open Process Review – Pending approvals of PRC-002-NPCC-01 in Canadian provinces
9.3.d C-29 Procedure for System Modeling: Data Requirements and Facility Ratings.
TFSS has requested a review of C-29 to consider the impact of the NERC MOD B project and to insure that the document can continue to be referenced in NPCC compliance assessments.
9.3.e C-42 Procedure for Reporting and Reviewing System Disturbances
TFCO to review to insure that the document can continue to be referenced in NPCC compliance assessments.
RSC October 2013 Meeting Item 11.0 RSC Meeting #13-5, Agenda Item 11.0: Standards Activity Post NERC BOT Approval
Page 1 of 22
LATEST CHANGES: Project 11.1: NERC Filings to FERC 11.2: FERC Orders / Rules 11.3: Federal Register Stage
Project WECC-0068 8/20/13: NERC Petition for approval of BAL-004-WECC-02 and BAL-001-1
Project: 2013-02, Paragraph 81
8/27/13: NERC submits comments in response to FERC June 20, 2013 Notice of Proposed Rulemaking (NOPR)
Project 2007-12 Frequency Response and Frequency Bias Setting
9/27/13 – NERC Comments on NOPR on Frequency Response NERC submits comments in response to the Notice of Proposed Rulemaking (NOPR) regarding proposed Reliability Standard BAL-003-1 (Frequency Response and Frequency Bias Setting)
Project 2007-17 Protection System Maintenance and Testing
9/9/13: NERC submits an Informational Filing Regarding the implementation of the modification to the definition of "Protection System" on the Glossary Terms in NERC 9/23/13: NERC submits comments on the Notice of Proposed Rulemaking (NOPR) regarding proposed Reliability Standard PRC-005-2
Project 2008-06 CIP V5
9/30/2013 - Errata to Petition for Approval of CIP Version 5 NERC submits Errata to Petition of NERC for Approval of Critical Infrastructure Protection Reliability Standards (CIP Version 5). Docket No. RM13-5-000 10/1/2013 - Errata to Petition for Approval of CIP Version 5 On September 30, 2013, NERC submitted errata to the proposed defined terms and Violation Severity Levels associated with version 5 of the Critical Infrastructure Protection Reliability Standards (“CIP Version 5”) pending before the Commission. NERC submits a replacement Attachment 2 that contains corrected clean and redline version of proposed CIP-002-5.1. Docket No. RM13-5-000
RSC October 2013 Meeting Item 11.0 RSC Meeting #13-5, Agenda Item 11.0: Standards Activity Post NERC BOT Approval
Page 2 of 22
Project 11.1: NERC Filings to FERC 11.2: FERC Orders / Rules 11.3: Federal Register Stage TRE Regional Standard BAL-001-TRE-01
9/18/13: Joint Petition of NERC and TRE for Approval of BAL-001-TRE-01 submitted
WECC Regional Standard BAL-002-WECC-2
9/23/13: NERC and WECC submitted comments in response to the Notice of Proposed Rulemaking (NOPR) proposing to approve regional Reliability Standard BAL-002-WECC-2
Project 2010-17 BES Definition and BES Exception Procedure
8/30/13: FERC issues an order denying the requested clarification or in the alternative rehearing, by National Rural Electric Cooperative Association and the American Public Power Association, of the Commission's Order No. 773-A.
Project 2007-07 Transmission Vegetation Management
9/4/13: FERC issues a letter order accepting NERC’s compliance filing without modification submitted in response to Order No. 777, which approved NERC’s proposed Reliability Standard FAC-003-2 (Transmission Vegetation Management)
Project 2010-07 Generator Requirements at the Transmission Interface
9/19/13: FERC issues a Final Rule approving revisions to four Reliability Standards that extend or clarify that applicability of those standards to Generator Owners and Generator Operators and/or to their generator interconnection Facilities.
9/24/13: Final Rule published in Federal Register. Rule effective November 25, 2013. Revised standards PRC-004.2.1a and PRC-005-1.1b will take effect November 25, 2013, revised standard FAC-001-1 and requirement R3 of FAC-003-3 will take effect on April 1, 2015, and the remaining requirements of FAC-003-3 will take effect on April 1, 2016.
Project 2007-09 Generator Verification
9/19/13: FERC issues Notice of Proposed Rulemaking to Approve Regional Reliability Standards MOD-025-2, MOD-026-1, MOD-027-1, PRC-019-1 and PRC-024-1
9/24/13: NOPR published in Federal Register. Comments due November 25, 2013 [Discuss FERC’s NOPR (RM13-16) on Generator Verification Standards relative to the impact and disposition of NPCC Directories 9 and 10]
Project 2010-13 9/10/13: Compliance filing in response to Commission Order Nos. 733 and 759 directing NERC to file a test for Planning Coordinators to identify sub 200kV critical facilities published in the Federal Register. Comments due September 20, 2013
RSC October 2013 Meeting Item 11.0 RSC Meeting #13-5, Agenda Item 11.0: Standards Activity Post NERC BOT Approval
Page 3 of 22
Project 11.1: NERC Filings to FERC 11.2: FERC Orders / Rules 11.3: Federal Register Stage Project 2010-13 9/27/2013 - Petition of NERC for Approval of
Proposed Reliability Standard PRC-025-1 NERC submits proposed Reliability Standard PRC-025-1- Generator Relay Loadability for approval.
9/10/13: Compliance filing in response to Commission Order Nos. 733 and 759 directing NERC to file a test for Planning Coordinators to identify sub 200kV critical facilities published in the Federal Register. Comments due September 20, 2013
RSC October 2013 Meeting Item 11.0 RSC Meeting #13-5, Agenda Item 11.0: Standards Activity Post NERC BOT Approval
Page 4 of 22
Project 11.1: NERC Filings to FERC 11.2: FERC Orders / Rules 11.3: Federal Register Stage Project: 2006-06, Reliability Coordination Approve: • IRO-001-3 • IRO-002-3 • IRO-005-4 • IRO-014-2 Retire: • IRO-001-1.1 • IRO-002-2 • IRO-005-3a • IRO-014-1 • IRO-015-1 • IRO-016-1
4/16/2013 - Petition of the North American Electric Reliability Corporation for Approval of Proposed Reliability Standards IRO-001-3, IRO-002-3, IRO-005-4, and IRO-014-2 NERC submits a Petition for Approval of Proposed Reliability Standards IRO-001-3, IRO-002-3, IRO-005-4, and IRO-014-2. Docket No. RM13-_-000
Filed and Pending Regulatory Approval Last Action: 4/16/13 - NERC Petition Filed
Project: 2007-03, Real-time Transmission Operations Approve: • TOP-001-2 • TOP-002-3 • TOP-003-2 • TOP-006-3 • PRC-001-2 Retire: • TOP-001-1a • TOP-002-2.1b • TOP-003-1 • TOP-004-2 • TOP-005-2a • TOP-006-2 • TOP-007-0 • TOP-008-1 • PER-001-0.2 • PRC-001-1, R2,
R5, and R6
4/16/2013 - Petition for Approval of Three Transmission Operation Standards, One Protection and Control Reliability Standard, and Retirement of Nine Existing Reliability Standards and One Requirement from an Existing Reliability Standard NERC submits a Petition for Approval of Three Transmission Operation Standards (TOP-001-2—Transmission Operations, TOP-002-3—Operations Planning, TOP-003-2—Operational Reliability Data) One Protection and Control Reliability Standard (PRC-001-2—System Protection Coordination), and Retirement of Nine Existing Reliability Standards and One Requirement from an Existing Reliability Standard. Docket No. RM13-_-000
Filed and Pending Regulatory Approval Last Action: 4/16/13 - NERC Petition Filed
RSC October 2013 Meeting Item 11.0 RSC Meeting #13-5, Agenda Item 11.0: Standards Activity Post NERC BOT Approval
Page 5 of 22
Project 11.1: NERC Filings to FERC 11.2: FERC Orders / Rules 11.3: Federal Register Stage Project: 2007-07 Transmission Vegetation Management Approve: • FAC-003-2 Retire: • FAC-003-1
12/21/2011 – Petition for Approval of Proposed Reliability Standard FAC-003-2 - Transmission Vegetation Management NERC files a Petition for Approval of Proposed Reliability Standard FAC-003-2 — Transmission Vegetation Management. Docket No. RM_-__-___ 4/24/2012 - Errata to Petition for Approval of FAC-003-2 NERC submits errata to the Petition for Approval of Proposed Reliability Standard FAC-003-2—Transmission Vegetation Management correcting a typo in the Compliance section of the standard. Docket No. RM12-4-000 5/3/2012 - Request for Information of NERC on the Notice Inviting Comments on the PNNL Report Concerning the Applicability of the Gallet Equation to the Vegetation Clearances of NERC Transmission Vegetation Management Reliability Standard FAC-003-2 NERC submits a request for information on the Notice Inviting Comments regarding related documents. Docket No. RM12-4-000 5/24/2012 - Comments of NERC in Response to PNNL Report on the Use of the Gallet Equation in FAC-003-2 NERC files comments in response to the report prepared by the Pacific Northwest National Laboratory (“PNNL”) on “Applicability of the ‘Gallet Equation’ to the Vegetation Clearances of NERC Reliability Standard FAC-003-2." Docket No. RM12-4-000 5/25/2012 - Response of NERC to FERC Office of Reliability's May 4, 2012 Data Request regarding FAC-003-2
Docket #: RM12-4-000 / Date: 4/23/2012 Title: Notice Inviting Comments on Report Prepared by PNNL on "Applicability of the 'Gallet Equation' to the Vegetation Clearances of NERC Reliability Standard FAC-003-2" Summary: FERC posts and invites comment upon a report prepared by the Pacific Northwest National Laboratory (PNNL) on “Applicability of the ‘Gallet Equation’ to the Vegetation Clearances of NERC Reliability Standard FAC-003-2” (PNNL Report). Docket No. RM12-4-000 Docket #: RM12-4-000 / Date: 5/4/2012 Title: Data Request in Response to the NERC Petition for Approval of Proposed Reliability Standard FAC-003-2 - Transmission Vegetation Management Summary: FERC issues a data request in response to NERC's Petition for Approval of Proposed Reliability Standard FAC- 003-2 – Transmission Vegetation Management order to better understand NERC’s petition. Docket No. RM12-4-000 Docket #: RM12-4-000 / Date: 10/18/2012 Title: NOPR on Revisions to Reliability Standards for Transmission Vegetation Management Summary: FERC issues a NOPR in which it proposes to approve Reliability Standard FAC-003-2 (Transmission Vegetation Management, the three definitions in the petition, the implementation plan and the Violation Severity Levels associated with the proposed Reliability Standard. The Commission proposes to direct that NERC revise the Violation Risk Factor for Requirement R2, and approve the remainder of the Violation Risk Factors. Docket No. RM12-4-000 Docket #: RM12-4-000 / Date: 3/21/2013 Title: Order No. 777 - Final Rule Approving FAC-003-2 - Transmission Vegetation Management
Vol. 78, No. 60 – Date: Thursday, March 28, 2013 RULES Revisions to Reliability Standard for Transmission Vegetation Management Key Dates: This rule became effective May 28, 2013 Enforceable: FAC-003-2 will be enforceable on July 1, 2014 Vol. 78, No. 74 – Date: Wednesday, April 17, 2013 RULES Revisions to Reliability Standard for Transmission Vegetation Management; Correction Key Dates: N/A - the following corrections are made: 1. On page 18826, in the third column, in paragraph
73, correct ‘‘45 days’’ to read ‘‘60 days’’ 2. On page 18827, in the first column, in paragraph
77, correct ‘‘45 days’’ to read ‘‘60 days’’
Subject to Future Enforcement Last Action: 9/4/13 – FERC Approved NERC Compliance Filing FAC-003-2 Enforceable: July 1, 2014
RSC October 2013 Meeting Item 11.0 RSC Meeting #13-5, Agenda Item 11.0: Standards Activity Post NERC BOT Approval
Page 6 of 22
Project 11.1: NERC Filings to FERC 11.2: FERC Orders / Rules 11.3: Federal Register Stage NERC files its response to the FERC Office of Electric Reliability’s May 4, 2012 Data Request regarding FAC-003-2. Docket No. RM12-4-000 12/21/2012 - Comments of NERC in response to NOPR on Transmission Vegetation Management Standard FAC-003-2 NERC submits comments in response to the October 18, 2012 Notice of Proposed Rulemaking proposing to approve Reliability Standard FAC-003-2. Docket No. RM12-4-000 2/5/2013 - Reply Comments of NERC in Response to Comments Submitting on NOPR on Transmission Vegetation Management Standard FAC-003-2 NERC submits reply comments to comments submitted on the NOPR on Revisions to Reliability Standards for Transmission Vegetation Management. Docket No. RM12-4-000 7/12/2013 - Compliance Filing of NERC FAC-003-2 NERC submits a compliance filing to: (1) provide a detailed description of NERC's plan to conduct testing to develop empirical data regarding the flashover distances between conductors and vegetation; (2) modify the Violation Rick Factor ("VRF") for Requirement R2; and (3) confirm NERC has posted guidance materials for NERC Reliability Standard FAC-003-2. Docket No. RM12-4-000
Summary: FERC issues a final rule approving Reliability Standard FAC-003-2 - Transmission Vegetation Management, and three new definitions in the NERC Glossary of Terms – “Right-of-Way,” “Vegetation Inspection,” and “Minimum Vegetation Clearance Distance.” FAC-003-2 also incorporates a new minimum annual inspection requirement, and incorporates new minimum vegetation clearance distances into the text of the standard. Docket No. RM12-4-000 Docket #: RM12-4-001 / Date: 9/4/2013 Title: NERC Compliance Filing in Response to Order No. 777 Summary: FERC issues a letter order accepting NERC’s compliance filing without modification submitted in response to Order No. 777, which approved NERC’s proposed Reliability Standard FAC-003-2 (Transmission Vegetation Management). In that order, the Commission directed NERC to (1) provide a description of NERC’s plan to conduct testing to develop empirical data regarding the flashover distances between conductors and vegetation; (2) modify the Violation Risk Factor for Requirement R2 from Medium to High; and (3) confirm that NERC has posted guidance materials for NERC Reliability Standard FAC-003-2 to its website. Enforceable: FAC-003-2 enforceable on July 1, 2014
RSC October 2013 Meeting Item 11.0 RSC Meeting #13-5, Agenda Item 11.0: Standards Activity Post NERC BOT Approval
Page 7 of 22
Project 11.1: NERC Filings to FERC 11.2: FERC Orders / Rules 11.3: Federal Register Stage Project: 2007-09 ― Generator Verification Approve: • MOD-025-2 • MOD-026-1 • MOD-027-1 • PRC-019-1 • PRC-024-1 Retire: • MOD-024-1
(pending regulatory approval)
• MOD-025-1 (pending regulatory approval)
5/30/2013 - Petition of NERC for Approval of Five Proposed Reliability Standards MOD-025-2, MOD-026-1, MOD-027-1, PRC-019-1 and PRC-024-1 Attachments to the Filing NERC submits a petition for five new Generator Verification Standards and their accompanying VRFs and VSLs. Docket No. RM_-_-000
Docket #: RM13-16-000 / Date: 9/19/2013 Title: Notice of Proposed Rulemaking to Approve Regional Reliability Standards MOD-025-2, MOD-026-1, MOD-027-1, PRC-019-1 and PRC-024-1 Summary: FERC issues a Notice of Proposed Rulemaking (NOPR) proposing to approve the proposed Reliability Standards. The Commission notes in the NOPR that, collectively, the proposed Reliability Standards improve the accuracy of model verifications needed to support reliability and enhance the coordination of generator protection systems and voltage regulating system controls. The Commission goes on to state that such improvements should help reduce the risk of generator trips and provide more accurate models for Transmission Planners and Planning Coordinators to develop system models and simulations.
Vol. 78, No. 185 – Date: Tuesday, September 24, 2013 PROPOSED RULES Generator Verification Reliability Standards Key Dates: Comments due 11/25/2013
Filed and Pending Regulatory Approval Last Action: 9/24/13 – NOPR published in Federal Register. Comments due November 25, 2013 Comments Due: 11/25/13
Project: 2007-12 ― Frequency Response and Frequency Bias Setting Approve: • BAL-003-1 Retire: • BAL-003-0.1b
3/29/2013 - Petition for Approval of Proposed Reliability Standard BAL-003-1 - Frequency Response and Frequency Bias Setting NERC submits a Petition of the North American Electric Reliability Corporation for Approval of Proposed Reliability Standard BAL-003-1 – Frequency Response and Frequency Bias Setting. The proposed standard ensures that each of the Interconnections have sufficient Frequency Response to guard against underfrequency load shedding (“UFLS”) due to an event in that Interconnection. Docket No. RM13-11-000 9/27/13 – NERC Comments on NOPR on Frequency Response NERC submits comments in response to the Notice of Proposed Rulemaking (NOPR) regarding proposed Reliability Standard BAL-003-1 (Frequency Response and Frequency Bias Setting)
Docket #: RM13-11-000 / Date: 7/18/2013 Title: Notice of Proposed Rulemaking (NOPR) on Reliability Standard BAL-003-1 Summary: The Commission proposes to approve Reliability Standard BAL-003-1 (Frequency Response and Frequency Bias Setting), submitted by the North American Electric Reliability Corporation, the Commission-certified Electric Reliability Organization. The proposed Reliability Standard defines the necessary amount of frequency response needed for reliable operations for each Balancing Authority within an Interconnection.
Vol. 78, No. 145 – Date: Monday, July 29, 2013 PROPOSED RULES Frequency Response and Frequency Bias Setting Reliability Standard Key Dates: Comments due 9/27/2013
Filed and Pending Regulatory Approval Last Action: 9/27/13 NERC Comments on NOPR on Frequency Response
RSC October 2013 Meeting Item 11.0 RSC Meeting #13-5, Agenda Item 11.0: Standards Activity Post NERC BOT Approval
Page 8 of 22
Project 11.1: NERC Filings to FERC 11.2: FERC Orders / Rules 11.3: Federal Register Stage Project: 2007-17 ― Protection System Maintenance and Testing Approve: • PRC-005-2 Retire: • PRC-005-1.1b • PRC-008-0 • PRC-011-0 • PRC-017-0
2/26/2013 - Petition for Approval of Proposed Reliability Standard PRC-005-2 - Protection System Maintenance NERC submits proposed Reliability Standard PRC-005-2 which consolidates Reliability Standards PRC-005-1.1b, PRC-008-0, PRC-011-0, and PRC-017-0 into a single proposed Reliability Standard. Proposed PRC-005-2 also addresses the directives related to those Reliability Standards issued by the Commission in Order No. 693. Docket No. RM13-7-000 9/9/13 - Informational Filing of NERC Regarding Definition of Protection System NERC submits an Informational Filing Regarding the implementation of the modification to the definition of "Protection System" on the Glossary Terms in NERC. Docket No. RD11-13-000 9/23/13 – Comments of NERC in Response to Notice of Proposed Rulemaking on PRC-005-2 (Protection System Maintenance) NERC submits comments on the Notice of Proposed Rulemaking (NOPR) regarding proposed Reliability Standard PRC-005-2. Docket No. RM13-7-000
Docket #: RM13-7-000 / Date: 7/18/2013 Title: Notice of Proposed Rulemaking to Approve PRC-005-2 Summary: FERC issues a Notice of Proposed Rulemaking (NOPR) to approve Reliability Standard PRC-005-02-Protection System Maintenance.
Vol. 78, No. 142 – Date: Wednesday, July 24, 2013 PROPOSED RULES Protection System Maintenance Reliability Standard Key Dates: Comments due 9/23/2013
Filed and Pending Regulatory Approval Last Action: 9/23/13 - NERC submits comments on the NOPR regarding proposed Reliability Standard PRC-005-2
RSC October 2013 Meeting Item 11.0 RSC Meeting #13-5, Agenda Item 11.0: Standards Activity Post NERC BOT Approval
Page 9 of 22
Project 11.1: NERC Filings to FERC 11.2: FERC Orders / Rules 11.3: Federal Register Stage Project: 2008-06, Cyber Security Order 706 Version 5 CIP Standards Approve: • CIP Version 5
Retire: • CIP Version 3 • CIP Version 4
1/31/2013 - Petition of NERC for Approval of CIP Version 5 Reliability Standards NERC submits a Petition for approval of Critical Infrastructure Protection Reliability Standards Version 5. Docket No. RM13-5-000 6/24/2013 - Comments of NERC on the Notice of Proposed Rulemaking for Version 5 Critical Infrastructure Protection Reliability Standards NERC submits comments on the Notice of Proposed Rulemaking (NOPR) regarding NERC's proposed Version 5 Critical Infrastructure Protection (CIP Version5) Reliability Standards issued by FERC on April 18, 2013. 9/30/2013 - Errata to Petition for Approval of CIP Version 5 NERC submits an Errata to Petition of NERC for Approval of Critical Infrastructure Protection Reliability Standards (CIP Version 5). Docket No. RM13-5-000 10/1/2013 - Errata to Petition for Approval of CIP Version 5 On September 30, 2013, NERC submitted errata to the proposed defined terms and Violation Severity Levels associated with version 5 of the Critical Infrastructure Protection Reliability Standards (“CIP Version 5”) pending before the Commission. NERC submits a replacement Attachment 2 that contains corrected clean and redline version of proposed CIP-002-5.1. Docket No. RM13-5-000
Docket #: RM13-5-000 / Date: 4/18/2013 Title: NOPR on Version 5 Critical Infrastructure Protection Reliability Standards Summary: FERC issues a Notice of Proposed Rulemaking proposing to approve the Version 5 CIP Standards. The proposed Reliability Standards, which pertain to the cyber security of the bulk electric system, represent an improvement over the current Commission-approved CIP Reliability Standards as they adopt new cyber security controls and extend the scope of the systems that are protected by the CIP Reliability Standards. Docket #: RM13-5-000 / Date: 5/3/2013 Title: Errata to FERC's Order on Version 5 CIP Reliability Standards Summary: FERC issues errata correcting minor typographical errors in the Order on Version 5 Critical Infrastructure Protection Reliability Standards. Docket #: RM11-11-000 (V4) & RM13-5-000 (V5) / Date: 8/12/2013 Title: Order Granting Extension of Time CIP Version 4 and 5 Summary: FERC issues an order granting extension of time on Version 4 of the Critical Infrastructure Protection (CIP) Reliability Standards. The Commission approved the Version 4 CIP Reliability Standards in Order 761. This order extends the effective date from April 1, 2014 to October 1, 2014. [Six-month extension is consistent with the NOPR proposal regarding implementation of the proposed V5 Standards (i.e., transition from V3 CIP directly to V5 CIP.]
Vol. 78, No. 79 – Date: Wednesday, April 24, 2013 PROPOSED RULES Version 5 Critical Infrastructure Protection Reliability Standards Key Dates: Comments were due 6/24/2013 Vol. 78, No. 90 – Date: Thursday, May 9, 2013 PROPOSED RULES Version 5 Critical Infrastructure Protection Reliability Standards - Errata Key Dates: N/A
Filed and Pending Regulatory Approval Last Action: 10/1/13 – NERC issues Errata to Petition for Approval
RSC October 2013 Meeting Item 11.0 RSC Meeting #13-5, Agenda Item 11.0: Standards Activity Post NERC BOT Approval
Page 10 of 22
Project 11.1: NERC Filings to FERC 11.2: FERC Orders / Rules 11.3: Federal Register Stage Project: 2009-01, Disturbance and Sabotage Reporting Approve: • EOP-004-2
Retire: • EOP-004-1 • CIP-001-2a
12/31/2012 - Petition for Approval of Proposed Reliability Standard EOP-004-2 - Event Reporting NERC submits a petition for approval of standard EOP-004-2 - Event Reporting. The proposed Reliability Standard provides a comprehensive approach to reporting disturbances and events that have the potential to impact the reliability of the Bulk Electric System in accordance with several Commission directives. Docket No. RD13-3-000 1/4/2013 - Errata to Petition for Approval of Proposed Reliability Standard EOP-004-2 - Event Reporting NERC submits errata making a minor correction to Exhibit B - Reliability Standard EOP-004-2. Docket No. RD13-3-000
Docket #: RD13-3-000 / Date: 6/20/2013 Title: Order Granting Approval for EOP-004-2 Summary: FERC issues an order approving EOP-004-2, which would replace two existing Reliability Standards, EOP-004-1- Disturbance Reporting and CIP-001-2a - Sabotage Reporting. EOP-004-2 is a Result Based Standards that merges EOP-004-1- and CIP-001-2a into a single event reporting standard. Enforceable: EOP-004-2 enforceable on January 1, 2014
N/A - Order is effective immediately (6/20/2013) Vol. 78, No. 135 – Date: Monday, July 15, 2013 ORDER APPROVING RELIABILITY STANDARDS Order Approving Reliability Standards: North American Electric Reliability Corp. [EOP-004-2] Key Dates: N/A
Subject to Future Enforcement Last Action: 7/15/13 – FERC Order Published in Federal Register EOP-004-2 Enforceable: January 1, 2014
Project: 2009-19, Interpretation of BAL-002-0 R4 and R5 by NWPP Reserve Sharing Group Approve: • BAL-002-1a
Retire: • BAL-002-1
2/12/2013 - Petition for Approval of Interpretation to BAL-002-1 - Disturbance Control Performance NERC submits a petition for approval of proposed interpretation BAL-002-1a, which includes an interpretation to Requirements R4 and R5 of BAL-002-1. Docket No. RD13-_-000 7/8/2013 - NERC Comments on Proposed Remand of BAL-002 NERC submits comments in response to the May 16, 2013 Notice of Proposed Rulemaking (NOPR) proposing to remand the proposed interpretation of Reliability Standard BAL-002-1. Docket No. RM13-6-000
Docket #: RM13-6-000 / Date: 5/16/2013 Title: NOPR Proposing to Remand Interpretation to BAL-002-1 - Disturbance Control Performance Summary: FERC issues a NOPR in which it proposes to remand a proposed interpretation to BAL-002-1, Requirements R4 and R5.
Vol. 78, No. 99 – Date: Wednesday, May 22, 2013 PROPOSED RULES Electric Reliability Organization Interpretation of Specific Requirements of the Disturbance Control Performance Standard Key Dates: Comments were due 7/8/2013
Filed and Pending Regulatory Approval Last Action: 7/8/13 – NERC Submits Comments [NERC urges FERC to accept the proposed interpretation as submitted]
RSC October 2013 Meeting Item 11.0 RSC Meeting #13-5, Agenda Item 11.0: Standards Activity Post NERC BOT Approval
Page 11 of 22
Project 11.1: NERC Filings to FERC 11.2: FERC Orders / Rules 11.3: Federal Register Stage Project: 2010-07, Generator Requirements at the Transmission Interface Approve: • FAC-001-1 • FAC-003-3 • PRC-004-2.1a • PRC-005-1.1b
Retire: • FAC-001-0 • FAC-003-1 / 2 • PRC-004-2a • PRC-005-1b
7/30/2012 - Petition for Approval of FAC-001-1, FAC-003-3, PRC-004-2.1a, and PRC-005-1.1b NERC submits a petition for approval of proposed Reliability Standards FAC-001-1 – Facility Connection Requirements, FAC-003-3 – Transmission Vegetation Management, PRC-004-2.1a – Analysis and Mitigation of Transmission and Generation Protection System Misoperations and PRC-005-1.1b - Transmission and Generation Protection System Maintenance and Testing. Docket No. RD12-16-000 6/24/2013 - Comments of the North American Electric Reliability Corporation on Generator Requirements at the Transmission Interface NOPR NERC submits comments in response to FERC's April 18, 2013 NOPR regarding modifications to four existing Reliability Standards, FAC -001-1 (Facility Connection Requirements), FAC -003-3 (Transmission Vegetation Management), PRC -004-2.1a (Analysis and Mitigation of Transmission and Generation Protection System Misoperations), and PRC -005-1.1b (Transmission and Generation Protection System Maintenance and Testing). Docket No. RM12-16-000 7/9/2013 - Reply Comments of NERC in Response to GOTO NOPR Comments NERC submits reply comments in response to the comments submitted on June 24, 2013 on the FERC April 18, 2013, Notice of Proposed Rulemaking (NOPR) regarding modifications to four existing Reliability Standards. Docket No. RM12-16-000
Docket #: RM12-16-000 / Date: 4/18/2013 Title: NOPR Proposing to Approve Generator Requirements at the Transmission Interface (GOTO) Summary: FERC issues at NOPR in which it proposes to approve Reliability Standards FAC-001-1 (Facility Connection Requirements), FAC-003-3 (Transmission Vegetation Management), PRC-004-2.1 (Analysis and Mitigation of Transmission and Generation Protection System Misoperations), and PRC-005-1.1b (Transmission and Generation Protection System Maintenance and Testing). The proposed modifications improve reliability either by extending their applicability to certain generator interconnection facilities, or by clarifying that the existing Reliability Standard is and remains applicable to generator interconnection facilities. Docket #: RM12-16-000 / Date: 9/19/2013 Title: Order on Final Rule Generator Requirements at the Transmission Interface Summary: FERC issues a Final Rule approving revisions to four Reliability Standards that extend or clarify that applicability of those standards to Generator Owners and Generator Operators and/or to their generator interconnection Facilities. In the final rule, the Commission also states that, while additional Reliability Standards or individual requirements may need to be applied on a case-by-case basis to generator interconnection Facilities in certain circumstances, for the majority of Generator Owners and Operators, NERC will not pursue registration of Generator Owners and Operators as Transmission Owners or Transmission Operators due solely to their ownership or operation of generator interconnection Facilities.
Vol. 78, No. 79 – Date: Wednesday, April 24, 2013 PROPOSED RULES Generator Requirements at the Transmission Interface Key Dates: Comments were due 6/24/2013 Vol. 78, No. 185 – Date: Tuesday, September 24, 2013 RULES Generator Requirements at the Transmission Interface Key Dates: Rule effective 11/25/13
Subject to Future Enforcement Last Action: 9/24/13 - NERC Final Rule published in Federal Register PRC-004.2.1a and PRC-005-1.1b Enforceable: November 25, 2013 FAC-001-1 and requirement R3 of FAC-003-3 Enforceable: April 1, 2015 Remaining requirements of FAC-003-3 Enforceable: April 1, 2016.
RSC October 2013 Meeting Item 11.0 RSC Meeting #13-5, Agenda Item 11.0: Standards Activity Post NERC BOT Approval
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Project 11.1: NERC Filings to FERC 11.2: FERC Orders / Rules 11.3: Federal Register Stage Project: 2010-INT-05, CIP-002-1 Requirement R3 for Duke Energy Approve: • CIP-002-4a
Retire: • CIP-002-4
4/22/2013 - Request for Clarification of NERC on Order Remanding Interpretation to CIP-002-4 NERC submits a request for clarification to the March 21, 2013 Order on Interpretation of Reliability Standard remanding NERC's proposed interpretation to CIP-002-4, Requirement R2. NERC seeks clarification on two specific issues. Docket No. RD12-5-000
Docket #: RD12-5-000 / Date: 3/21/2013 Title: Order Remanding Interpretation to CIP-002-4 - Critical Cyber Asset Identification Summary: FERC issues an order in which it remands the proposed interpretation to Reliability Standard CIP-002-4, Requirement R3. Docket #: RD12-5-001 / Date: 5/20/2013 Title: Order Granting Rehearing for Further Consideration on CIP-002-4 Remand Summary: FERC issues an order granting rehearing for further consideration on the order remanding the proposed interpretation to CIP-002-4 issued on March 21, 2013. Docket #: RD12-5-001 / Date: 6/25/2013 Title: Order on Clarification on Proposed Interpretation of CIP 002 Summary: FERC issues an order for clarification of the March 21, 2013 Order on Interpretation of Reliability Standards, in which the Commission remanded NERC's proposed interpretation of Critical Infrastructure Protection (CIP) Reliability Standard CIP -002.
Interpretation Remanded Last Action: 6/25/13 – FERC Issues Order on Clarification
RSC October 2013 Meeting Item 11.0 RSC Meeting #13-5, Agenda Item 11.0: Standards Activity Post NERC BOT Approval
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Project 11.1: NERC Filings to FERC 11.2: FERC Orders / Rules 11.3: Federal Register Stage Project: 2010-11 TPL Table 1 Order Approve: • TPL-001-4
Retire: • TPL-001-0.1 • TPL-002-0b • TPL-003-0a • TPL-004-0
Withdrawal: • TPL-001-1 /2 • TPL-002-2b • TPL-003-2a / 2b • TPL-004-2 / 2a • TPL-005-0 • TPL-006-0.1
2/28/2013 - Petition of NERC for Approval of Modified Transmission Planning Reliability Standards in the Case of System Performance Following Loss of a Single Bulk Electric System Element NERC submits a Petition for Approval of Modified Transmission Planning Reliability Standards that include changes to the requirements and processes for planned load shed in the event of a single Contingency that are identified in a revised footnote. NERC is also requesting Commission approval of revisions to the Standards that correspond to the Footnote revisions included in this Petition and other related documents. 6/24/2013 - Comments of the North American Electric Reliability Corporation in Response to Supplemental Notice of Proposed Rulemaking TPL -001-4 NERC submits comments in response to FERC's May 16, 2013 Supplemental Notice of Proposed Rulemaking (NOPR) regarding Reliability Standard TPL -001-4. The proposed modifications improve reliability and resolve issues and concerns with previous standards. The supplemental NOPR proposes to approve Reliability Standard TPL -001-4.
Docket #: RM12-1-000 & RM13-9-000 / Date: 5/16/2013 Title: Supplemental NOPR on Transmission Planning Reliability Standard TPL-001-2 Summary: FERC issues a NOPR in which it proposes to approve TPL-001-4, which supersedes TPL-001-2.
Vol. 78, No. 100 – Date: Thursday, May 23, 2013 PROPOSED RULES Transmission Planning Reliability Standards Key Dates: Comments were due 6/24/2013
Filed and Pending Regulatory Approval Last Action: 6/24/13 - NERC NOPR Comments Submitted
Project: 2010-13 Relay Loadability Approve: • PRC-025-1
9/27/2013 - Petition of NERC for Approval of Proposed Reliability Standard PRC-025-1 NERC submits proposed Reliability Standard PRC-025-1- Generator Relay Loadability for approval.
Vol. 78, No. 175 - Tuesday, September 10, 2013 COMPLIANCE FILINGS: Transmission Relay Loadability Reliability Standard Compliance filing in response to Commission Order Nos. 733 and 759 directing NERC to file a test for Planning Coordinators to identify sub-200kV critical facilities Key Dates: Comments due September 20, 2013
Enforceable Last Action: 9/10/13 – Compliance Filing Comments Due: 9/20/13
Project: 2010-17, BES Definition and BES Exception
1/25/2012 - Petition for Approval of a Revised Definition of "Bulk Electric System" in the NERC Glossary of Terms Used in Reliability Standards
Docket #: RM12-6-000 & RM12-7-000 / Date: 12/20/2012 Title: Order No 773 - Final Rule on the Revisions to
Vol. 78, No. 3 – Date: Friday, January 4, 2013 RULES Revisions to Electric Reliability Organization
Subject to Future Enforcement
RSC October 2013 Meeting Item 11.0 RSC Meeting #13-5, Agenda Item 11.0: Standards Activity Post NERC BOT Approval
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Project 11.1: NERC Filings to FERC 11.2: FERC Orders / Rules 11.3: Federal Register Stage Procedure Approve: • New BES
Definition • BES Exception
Procedure (ROP) Retire: • Existing BES
Definition
NERC submits a Petition for Approval of a Revised Definition of “Bulk Electric System” in the NERC Glossary of Terms Used in Reliability Standards. Docket No. RM12-6-000 4/4/2013 - Compliance Filing in Response to Order No. 773 - Approving Revisions to the ERO Definition of BES and Rules of Procedure NERC submits a filing in response to Order No. 773 Approving Revisions to the Electric Reliability Organization Definition of Bulk Electric System and Rules of Procedure. By this filing, NERC submits a schedule outlining how and when it will modify Exclusion E3 of the Bulk-Electric System definition to remove the 100 kV minimum operating voltage in the local network definition. Docket Nos. RM12-6-000 and RM12-7-000
the Electric Reliability Organization Definition of Bulk Electric System and Rules of Procedure Summary: FERC issues an order in which it approves modifications to the currently-effective definition of “bulk electric system” developed by NERC. Docket Nos. RM12-6-000 and RM12-7-000 Docket #: RM12-6-001 & RM12-7-001 / Date: 4/18/2013 Title: Order No. 773-A on Rehearing and Clarification of Order No. 773 - Revisions to the ERO Definition of BES and Rules of Procedure Summary: Order No. 773 approved modifications to the currently effective definition of “bulk electric system” and revisions to the NERC Rules of Procedure. Order No. 773-A denies rehearing in part, grants rehearing in part, and otherwise reaffirms FERC’s determinations in Order No. 773. Docket Nos. RM12-6-001 and RM12-7-001 Docket #: RM12-6-001 & RM12-7-001 / Date: 5/6/2013 Title: Errata to FERC Order on Revisions to ERO Definition of BES and Rules of Procedure Summary: FERC issues errata correcting minor typographical errors in the Order on the ERO Definition of Bulk Electric System (BES) and Rules of Procedure Docket #: RM12-6-000 & RM12-7-000 / Date: 6/13/2013 Title: Order Granting Extension of Time Summary: FERC issues an order granting an extension of time on the Bulk Electric System definition effective date and the Rules of Procedure exception process, issued today by FERC in Docket NOS. RM126-6-000 and RM12-7-000. This order extends the effective date from July 1, 2013 to July 1, 2014.
Definition of Bulk Electric System and Rules of Procedure [Order No. 773] Key Dates: This Final Rule became effective March 5, 2013 Vol. 78, No. 96 – Date: Friday, May 17, 2013 RULES Revisions to Electric Reliability Organization Definition of Bulk Electric System and Rules of Procedure [Order No. 773-A]
Last Action: 8/30/13 – Order Denying Request for Clarification and Rehearing Revised BES Definition Enforceable: July 1, 2014
RSC October 2013 Meeting Item 11.0 RSC Meeting #13-5, Agenda Item 11.0: Standards Activity Post NERC BOT Approval
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Project 11.1: NERC Filings to FERC 11.2: FERC Orders / Rules 11.3: Federal Register Stage Docket #: RM12-6-002 & RM12-7-002 / Date: 8/30/2013 Title: Order Denying Request for Clarification and Rehearing Summary: FERC issues an order denying the requested clarification or in the alternative rehearing, by National Rural Electric Cooperative Association and the American Public Power Association, of the Commission's Order No. 773-A.. Enforceable: Revised BES Definition enforceable on July 1, 2014
RSC October 2013 Meeting Item 11.0 RSC Meeting #13-5, Agenda Item 11.0: Standards Activity Post NERC BOT Approval
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Project 11.1: NERC Filings to FERC 11.2: FERC Orders / Rules 11.3: Federal Register Stage Project: 2011-INT-01, Interpretation of MOD-028, R3.1 for FPL Approve: • MOD-028-2
Retire: • MOD-028-1
8/24/2012 - Petition for Approval of MOD-028-2 - Area Interchange Methodology NERC submits a petition for approval of proposed Reliability Standard MOD-028-2 - Area Interchange Methodology. Docket No. RD_-_-___ 5/13/2013 - Comments in Response to NOPR Proposing to Approve MOD-028-2 NERC submits comments in response to FERC's March 21, 2013 Notice of Proposed Rulemaking proposing to approve MOD-028-2. Docket No. RM12-19-000
Docket #: RM12-19-000 / Date: 3/21/2013 Title: Notice of Proposed Ruling Proposing to Approve MOD-028-2 - Area Interchange Methodology Summary: FERC issues a NOPR in which it proposes to approve Reliability Standard MOD-028-1 - Area Interchange Methodology pertaining to the information a transmission service provider must include when calculating Total Transfer Capability using the area interchange methodology for the on-peak and off-peak intra-day and next day time periods. The Commission also proposes to approve NERC’s proposed implementation plan and retirement of the currently-effective standard. Docket #: RM12-19-000 / Date: 7/18/2013 Title: Order No. 782 - Final Rule Approving Revisions to Modeling, Data, and Analysis Reliability Standard MOD-028-2 Summary: In this Final Rule, pursuant to section 215 of the Federal Power Act, the Federal Energy Regulatory Commission (Commission) approves Modeling, Data, and Analysis (MOD) Reliability Standard MOD-028-2, submitted to the Commission for approval by the North American Electric Reliability Corporation (NERC), the Commission-certified Electric Reliability Organization. The Commission finds that the proposed Reliability Standard represents an improvement over the currently-effective standard, MOD-028-1 because the proposed Reliability Standard clarifies the timing and frequency of Total Transfer Capability calculations needed for Available Transfer Capability calculations. The Commission also approves NERC’s proposed implementation plan and retirement of the currently-effective standard. Enforceable: MOD-028-2 enforceable on October 1, 2013
Vol. 78, No. 61 – Date: Friday, March 29, 2013 PROPOSED RULES Revisions to Modeling, Data, and Analysis Reliability Standard Key Dates: Comments were due 5/13/2013 Vol. 78, No. 145 – Date: Monday, July 29, 2013 RULES Revisions to Modeling, Data, and Analysis Reliability Standard Key Dates: This rule will become effective September 27, 2013
Subject to Future Enforcement Last Action: 7/29/13 – FERC Order Published in Federal Register MOD-028-2 Enforceable: October 1, 2013
RSC October 2013 Meeting Item 11.0 RSC Meeting #13-5, Agenda Item 11.0: Standards Activity Post NERC BOT Approval
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Project 11.1: NERC Filings to FERC 11.2: FERC Orders / Rules 11.3: Federal Register Stage Project: 2011-INT-02, (Rapid Revision) VAR-002-2b Approve: • VAR-002-2b
Retire: • VAR-002-1.1b
11/21/2012 - Petition for Approval of Proposed Reliability Standard VAR-002-2b NERC submits a petition for approval of VAR-002-2b— Generator Operation for Maintaining Network Voltage Schedules, approval of the proposed Reliability Standard, the associated implementation plan, Violation Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”), and retirement of the currently effective Reliability Standard VAR-002-1.1b. Docket No. RD13-2-000 1/23/2013 - Reply Comments of NERC on Petition for Approval of Reliability Standard VAR-002-2b NERC submits Reply Comments in response to comments submitted on NERC’s Petition for Approval of Proposed Reliability Standard VAR-002-2b concerning the Violation Severity Level for Requirement R2. Docket No. RD13-2-000
Docket #: RD13-2-000 / Date: 4/16/2013 Title: Order Approving Reliability Standard VAR-002-2b Summary: FERC issues an order in which it approves Reliability Standard VAR-002-2b - Generator Operation for Maintaining Network Voltage Schedules, the associated VSLs and VRFs, and an implementation plan for VAR-002-2b. The revised Reliability Standard VAR-002-2b ensures that generators provide reactive and voltage control necessary to ensure voltage levels, reactive flows, and reactive resources are maintained within applicable facility ratings to protect equipment and the reliable operation of the interconnection. Enforceable: VAR-002-2b enforceable on January 1, 2014
N/A - Order is effective immediately (4/16/2013) Subject to Future Enforcement Last Action: 4/16/13 – FERC Order Issued VAR-002-2 Enforceable: January 1, 2014
RSC October 2013 Meeting Item 11.0 RSC Meeting #13-5, Agenda Item 11.0: Standards Activity Post NERC BOT Approval
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Project 11.1: NERC Filings to FERC 11.2: FERC Orders / Rules 11.3: Federal Register Stage Project: 2012-INT-02, Interpretation of TPL-003-0a and TPL-004-0 for SPCS Approve: • TPL-003-0b • TPL-004-0a Retire: • TPL-003-0a • TPL-004-0
4/12/2013 - Petition for Approval of an Interpretation to TPL-003-0a and TPL-004-0 NERC submits a Petition for Approval of an Interpretation to Reliability Standards TPL-003-0a and TPL-004-0. Docket No. RD13-8-000
Docket #: RD13-8-000 / Date: 6/20/2013 Title: Letter Order Granting Petition for Approval of the Interpretation to TPL-003-0a and TPL-004-0 Summary: FERC issues a letter order granting approval of the proposed interpretation to certain requirements for two Reliability Standards: TPL-003-0a (System Performance Following Loss of Two or More Bulk Electric System Elements (Category C)) and TPL-004-0 (System Performance Following Extreme Events Resulting in the Loss of Two or More Bulk Electric System Elements (Category D)). Interpretation Response: 1. Entity must evaluate both conditions presented in
Table 1 2. Entity is permitted to use “engineering judgment”
to select the protection system component failures for evaluation
Enforceable: TPL-003-0b and TPL-004-0a enforceable on June 20, 2013
N/A - Order is effective immediately (6/20/2013) Subject to Enforcement Last Action: 6/20/13 – FERC Order Issued TPL-003-0b & TPL-004-0a Enforceable: June 20, 2013
Project 2012-08.1 Phase 1 of Glossary Updates: Statutory Definitions • Bulk-Power
System • Reliable
Operation • Reliability
Standard
5/10/2013 - Petition for Approval of the NERC Glossary Terms "Bulk-Power System," "Reliable Operation" and "Reliability Standard" NERC submits a Petition for Approval of the NERC Glossary Terms "Bulk-Power System," "Reliable Operation" and "Reliability Standard." Docket No. RD13-10-000
Docket #: RD13-10-000 / Date: 7/9/2013 Title: Letter Order on Glossary Definitions RM13-10-000 Summary: FERC issues a letter order granting approval of the NERC Glossary Terms "Bulk-Power System," "Reliable Operation" and "Reliability Standard." Enforceable: Phase 1 of Glossary Updates: Statutory Definitions enforceable on July 9, 2013
N/A - Order is effective immediately (7/9/2013) Subject to Enforcement Last Action: 7/9/13 – FERC Order Issued
RSC October 2013 Meeting Item 11.0 RSC Meeting #13-5, Agenda Item 11.0: Standards Activity Post NERC BOT Approval
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Project 11.1: NERC Filings to FERC 11.2: FERC Orders / Rules 11.3: Federal Register Stage Project: 2013-02, Paragraph 81 NOPR proposing to: • Retire 34
requirements within 19 Reliability Standards
• Withdraw 41 outstanding Commission directives
2/28/2013 - Petition of NERC for Approval of Retirement of Requirements in Reliability Standards NERC submits a petition requesting approval of the retirement of 34 requirements within 19 currently effective Reliability Standards that are redundant or otherwise unnecessary, and for which violations of these requirements (currently included in Reliability Standards) pose a lesser risk to the reliability of the Bulk-Power System. Docket No. RM13-8-000 8/27/2013 - NERC Comments on the P81 Notice of Proposed Rulemaking NERC submits comments in response to FERC June 20, 2013 Notice of Proposed Rulemaking (NOPR) proposing to approve NERC's petition to retire 34 Requirements within 19 Reliability Standards and proposing to withdraw 41 outstanding directives. Docket No. RM13-8-000
Docket #: RM13-8-000 / Date: 6/20/2013 Title: NOPR on Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards Summary: FERC issues a Notice of Proposed Rulemaking (NOPR) proposing to retire 34 requirements within 19 Reliability Standards that are redundant or otherwise unnecessary, and where violations of these requirements pose a lesser risk to the reliability of the Bulk-Power System. In addition, the NOPR proposes to withdraw 41 outstanding Commission directives that NERC make modifications to Reliability Standards that have been addressed in some other manner, are redundant with another directive, or provide general guidance as opposed to a specific directive.
Vol. 78, No. 125 – Date: Friday, June 28, 2013 PROPOSED RULES Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards Key Dates: Comments due 8/27/2013 Vol. 78, No. 132 – Date: Wednesday, July 10, 2013 PROPOSED RULES Electric Reliability Organization Proposal to Retire; Correction Key Dates: N/A – the following corrections are made to the proposed rule published in the Federal Register on Friday, June 28, 2013: 1. In ¶90, the estimate ‘‘$535,500’’ in the first
sentence is changed to ‘‘$518,220.’’ 2. In the table in ¶90, the ‘‘Estimated Total Annual
Reduction in Burden (in hours)’’ for FAC–013–2, R3 and INT–007–1, R1.2 is changed from ‘‘1,600’’ to ‘‘640’’ and from ‘‘448’’ to ‘‘1,120,’’ respectively, and the Total is changed from ‘‘8,925’’ to ‘‘8,637.’’
3. In the table in ¶90, the ‘‘Estimated Total Annual Reduction in Cost’’ for FAC–013–2, R3 and INT–007–1, R1.2 is changed from ‘‘$96,000’’ to ‘‘$38,400’’ and from ‘‘$26,880’’ to ‘‘$67,200,’’ respectively, and the Total is changed from ‘‘$535,500’’ to ‘‘$518,220.’’
Filed and Pending Regulatory Approval Last Actions: 8/27/13 – NERC submits comments in response to FERC June 20, 2013 Notice of Proposed Rulemaking (NOPR)
RSC October 2013 Meeting Item 11.0 RSC Meeting #13-5, Agenda Item 11.0: Standards Activity Post NERC BOT Approval
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Project 11.1: NERC Filings to FERC 11.2: FERC Orders / Rules 11.3: Federal Register Stage Project: 2013-03, Geomagnetic Disturbance Mitigation
5/21/2012 - Comments of NERC Following the Technical Conference on Geomagnetic Disturbances to the Bulk-Power System NERC files comments following the FERC Technical Conference held on April 30, 2012 regarding Geomagnetic Disturbances to the Bulk Power System. Docket No. AD12-13-000 12/26/2012 - Comments of NERC in Response to NOPR Proposing NERC Develop Geomagnetic Disturbance Standards NERC submits comments in response to the October 18, 2012 Notice of Proposed Rulemaking proposing to direct NERC to file for approval with the Commission Reliability Standards that address the risks posed by geomagnetic disturbances (“GMDs”) to the reliable operation of the Bulk-Power System, in two stages. Docket No. RM12-22-000 1/10/2013 - Reply Comments of NERC in Response to Notice of Proposed Rulemaking on Reliability Standards for Geomagnetic Disturbances NERC submits comments in response to comments submitted in response to the Notice of Proposed Rulemaking on Reliability Standards for Geomagnetic Disturbances. Docket No. RM12-22-000
Docket #: RM12-22-000 / Date: 10/18/2012 Title: NOPR Proposing to Direct NERC to Develop and Submit Geomagnetic Disturbance Reliability Standards Summary: FERC issues a NOPR in which it proposes to direct NERC to file for approval with the Commission Reliability Standards (GMD Reliability Standards) that address the risks posed by geomagnetic disturbances (GMD) to the reliable operation of the Bulk-Power System. Docket No. RM12-22-000 Docket #: RM12-22-000 / Date: 5/16/2013 Title: Order No. 779 - Final Rule on Reliability Standard for Geomagnetic Disturbances Summary: FERC issues Order No. 779, in which it directs NERC to submit to the Commission for approval proposed Reliability Standards that address the impact of GMD on the reliable operation of the Bulk-Power System. The Commission directs NERC to implement the directive in two stages.
Vol. 78, No. 100 – Date: May 23, 2013 RULES Reliability Standards for Geomagnetic Disturbances Key Dates: Order becomes effective on July 22, 2013
Under Development Last Action: 5/23/2013 – FERC Order Published in Federal Register Order Effective: 7/22/ 13 [NERC must develop reliability standard]
Definition of Adequate Level of Reliability
5/10/2013 - Informational Filing on the Definition of "Adequate Level of Reliability" NERC submits an Informational Filing on the definition of "Adequate Level of Reliability" and a supporting technical report. Docket No. RR06-1-000
N/A - informational filing the definition of “Adequate Level of Reliability” that the NERC Board of Trustees approved on May 9, 2013 and a supporting technical report. NERC is not requesting the Commission to take any action on this definition.
N/A - informational filing the definition of “Adequate Level of Reliability” that the NERC Board of Trustees approved on May 9, 2013 and a supporting technical report. NERC is not requesting the Commission to take any action on this definition.
Completed Last Action: 5/10/13 – Informal Filing
RSC October 2013 Meeting Item 11.0 RSC Meeting #13-5, Agenda Item 11.0: Standards Activity Post NERC BOT Approval
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Project 11.1: NERC Filings to FERC 11.2: FERC Orders / Rules 11.3: Federal Register Stage Standards Processes Manual Revisions to Implement SPIG Recommendation
2/28/2013 - Petition of NERC for Approval of Revisions to the NERC Standard Processes Manual NERC files a petition for approval of revisions to the NERC Standards Process Manual (SPM). The SPM contains all of the procedures governing the Reliability Standards development process. The proposed revisions to the SPM enhance the Reliability Standards development process by providing additional clarity and streamlining the drafting, commenting and balloting processes. Docket Nos. RR12-3-000 and RR10-12-000 4/5/2013 - Reply Comments of NERC in Response to Comment on NERC Revisions to the Standard Processes Manual NERC submits comments in response to the comments of the City of Santa Clara made on NERC's Filing for Approval of Revisions to the NERC Standard Processes Manual. Docket No. RR13-2-000
Docket #: RR13-2-000 / Date: 6/26/2013 Title: Order Approving Revisions to Electric Reliability Organization's Standard Processes Manual Summary: FERC issues an order approving the proposed SPM modifications as reasonable, allowing for greater flexibility and efficiency in the Reliability Standards development process. FERC notes that the revised provisions recognize the need for highly qualified standards drafting teams that include technical writers, legal compliance, and rigorous and highly trained project management.
N/A - Order is effective immediately FERC Approved Last Action: 6/26/13 – FERC Order Issued New SPM (Appendix 3A of NERC RoP) effective June 26, 2013
TRE Regional Standard BAL-001-TRE-01
9/18/13: Joint Petition of NERC and TRE for Approval of BAL-001-TRE-01 submitted
Filed and Pending Regulatory Approval
WECC Regional Standard BAL-002-WECC-2
9/23/13: NERC and WECC submitted comments in response to the Notice of Proposed Rulemaking (NOPR) proposing to approve regional Reliability Standard BAL-002-WECC-2
Filed and Pending Regulatory Approval
RSC October 2013 Meeting Item 11.0 RSC Meeting #13-5, Agenda Item 11.0: Standards Activity Post NERC BOT Approval
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Project 11.1: NERC Filings to FERC 11.2: FERC Orders / Rules 11.3: Federal Register Stage Project: WECC-0046, Regional Variance Approve: • VAR-001-3
Retire: • VAR-001-2
2/25/2013 - Petition for Approval of Proposed Reliability Standard VAR-001-3 - Voltage and Reactive Control NERC submits a petition for approval of proposed Reliability Standard VAR-001-3 (Voltage and Reactive Control) developed by NERC and WECC that adds a regional variance developed by WECC as Section E of proposed VAR-001-3. Docket No. RD12-_-000
Docket #: RD13-6-000 / Date: 6/20/2013 Title: Letter Order Granting Approval of Proposed Reliability Standard VAR-001-3 Summary: FERC issues a letter order granting approval of proposed Reliability Standard VAR-001-3 (Voltage and Reactive Control), its associated implementation plan, Violation Risk Factors, Violation Severity Levels, and retirement of VAR-001-2. Scope: WECC Regional Variance for R3 and R4 Enforceable: VAR-001-3 will be enforceable on January 1, 2014
N/A - Order is effective immediately Subject to Future Enforcement Last Action: 6/20/13 – FERC Order Issued VAR-001-3 Enforceable: January 1, 2014
Project: WECC-0068 Approve: • BAL-004-WECC-2 • BAL-001-1 • NERC Glossary: o Area control
Error (ACE) o Automatic Time
Error Correction (ATEC)
Retire: • BAL-004-WECC-1 • BAL-001-0.1a • Appendix 1
Interpretation of Requirement R3 in Reliability Standard BAL-003-0.1b – Frequency Response and Bias
8/20/2013 - Joint Petition of NERC and WECC for Approval of BAL-004-WECC-02 and BAL-001-1 NERC submits a joint petition for approval of proposed regional Reliability Standard BAL-004-WECC-02 and proposed Reliability Standard BAL-001-1.
Filed and Pending Regulatory Approval Last Action: 8/20/13 - NERC Petition Filed
RSC October 2013 Meeting Item 13.0 RSC Meeting #13-5, Agenda Item 13.0: NERC Compliance Tools
Page 1 of 1
13.1 Compliance Application Notices (CANs) http://www.nerc.com/pa/comp/Resources/Pages/Compliance-Application-Notices.aspx 13.1.1 There have not been any CANs posted or retired since the last RSC meeting
Note: NERC has indicated: “To further streamline compliance related communication tools, and support the efforts of the Reliability Assurance Initiative (RAI), the Compliance Application Notice (CAN) process will be phased out during 2013. All currently active CANs will remain in effect until they can be transitioned into either the Reliability Standard Auditor Worksheets (RSAWs) or other acceptable compliance communication tool, at which time the CAN will be retired.”
13.2 Compliance Analysis Reports (CARs) http://www.nerc.com/pa/comp/Pages/Compliance-Analysis-Reports.aspx 13.2.1 There have not been any CARs posted since the last RSC meeting
13.3 Reliability Standard Audit Worksheets (RSAWs) http://www.nerc.com/pa/comp/Pages/Reliability-Standard-Audit-Worksheets-(RSAWs).aspx 13.3.1 There have not been any RSAWs posted since the last RSC meeting
