agenda standards committee - nerc highlights and minutes/sc...antitrust compliance guidelines i....

Agenda Standards Committee July 18, 2013 | 1:00 p.m. – 5:00 p.m. ET Phone Number: 1-866-740-1260 Meeting Code: 5247071 Security Code: 071813 Click here for: Webinar Registration Introductions and Chair’s Remarks NERC Antitrust Compliance Guidelines and Public Announcement* Agenda Items

1. Review of Agenda― (Approve) (5 minutes)

2. Consent Agenda― (Approve) (10 minutes)

a. June 5, 2013 Standards Committee Meeting Minutes*― (Approve)

3. Projects Under Development― (Review)

a. Project Tracking Spreadsheet (J. Sterling, R. Parsons, V. Agnew, H. Gugel, L. Hussey) (15 minutes)

b. Projected Posting Schedule (K. Iwanechko) (5 minutes)

4. MOD B: Modeling Data* (V. Agnew, S. Noess) (15 minutes)

a. Post the SAR and Standard(s)― (Authorize)

b. Solicit Nominations for MOD B: Modeling Data― (Approve)

5. MOD C: Demand Data* (V. Agnew, D. Richardson) (15 minutes)


b. Solicit Nominations for MOD C: Demand Data― (Approve)

6. PER: Training* (V. Agnew, J. Mallory) (15 minutes)


b. Solicit Nominations for PER: Training― (Approve)

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Standards Committee July 2013 Agenda 2

7. VAR: Reactive Power* (V. Agnew, S. Kim) (15 minutes)


b. Solicit Nominations for VAR: Reactive Power― (Approve)

8. Report on July 9th FERC Technical Conference― (Discussion) (M. Lauby, B. Murphy, J. Anderson, L. Campbell) (20 minutes)

9. Status of 2014-2016 Reliability Standards Development Plan and Next Steps― (Discussion) (S. Noess, L. Oberski, C. Yeung, B. Hampton) (15 minutes)

10. Subcommittee Reports

a. Communication and Planning Subcommittee Recommendations*― (Approve) (M. Huggins) (15 minutes)

b. Process Subcommittee* (20 minutes)

i. Status Overview (B. Li)

ii. Update on CEAP Activities (G. Zito)

c. Project Management and Oversight Subcommittee* (J. Sterling, R. Parsons) (15 minutes)

d. Functional Model Working Group*

i. 2013-2015 Work Plan Task 6, Part 3: FMWG Reforms― (Approve) (B. Murphy, J. Cyrulewski) (20 minutes)

11. Upcoming Standards Filings*― (Review) (S. Tyrewala) (10 minutes)

12. Informational Items― (Enclosed)

a. SC Expectations*

b. Standards Committee Roster*

c. Highlights of Parliamentary Procedure*

d. Schedule and Locations for 2013 Meetings*

13. Adjourn

*Background materials included.

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

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

• Discussions of a participant’s marketing strategies.

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

• Discussions concerning the exclusion of competitors from markets.

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

NERC Antitrust Compliance Guidelines 2

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

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

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

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

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

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

Public Announcements REMINDER FOR USE AT BEGINNING OF MEETINGS AND CONFERENCE CALLS THAT HAVE BEEN PUBLICLY NOTICED AND ARE OPEN TO THE PUBLIC Conference call version: Participants are reminded that this conference call is public. The access number was posted on the NERC website and widely distributed. Speakers on the call should keep in mind that the listening audience may include members of the press and representatives of various governmental authorities, in addition to the expected participation by industry stakeholders.

Meeting Minutes Standards Committee June 5, 2013 | 8:00 a.m. – 5:00 p.m. ET June 6, 2013 | 8:00 a.m. – 3:00 p.m. ET Introductions and Chair’s Remarks Chairman Brian Murphy welcomed the Committee members and observers and determined the presence of a quorum. The attendance of Standards Committee members is provided in Attachment A. Gerry Cauley, President and Chief Executive Officer of NERC, stated that NERC standards are in an excellent position due to the hard work of the Standards Committee and those working on the standards development process. He believes there is a good plan in place and is confident about NERC and the Committee’s ability to get the work done. Mr. Cauley appreciated the Committee’s sense of accountability and direction to transform the standards into a steady-state body of high quality, results-based standards. B. Murphy echoed Mr. Cauley’s remarks. He summarized the items acted on by the Executive Committee since the last Standards Committee meeting. Prior to the next scheduled Standards Committee meeting, B. Murphy noted that there may be a number of items for Committee action including transitioning the informal ad hoc groups to standard drafting teams and soliciting new members, authorizing the Geomagnetic Disturbance Mitigation project for posting, and the Independent Standards Review Panel’s final report. He also stated that some of these items may be handled via email ballot or an Executive Committee meeting. If necessary, an interim call with the entire Committee may be scheduled. B. Murphy also reminded the Committee that five-year review recommendations will be posted for industry comment in the near future and the recommendations and stakeholder input will be presented to the Committee. B. Murphy also presented a revised schedule for submitting agenda items and background material for Committee meetings, which allows for a few extra days to submit materials, while still posting the agenda no later than five business days prior to the scheduled meeting. NERC Antitrust Compliance Guidelines and Public Announcement Kristin Iwanechko reviewed the NERC Antitrust Compliance Guidelines and reminded participants that notice of the meeting had been widely distributed. Agenda Items

1. Review of Agenda

F. Plett motioned to approve the agenda. F. Gaffney seconded the motion.

Agenda Item 2a Standards Committee

July 18, 2013

Standards Committee June 2013 Minutes 2

- The Committee approved the motion with no objections or abstentions.

2. Consent Agenda

a. May 2, 2013 Standards Committee Meeting Minutes

b. Solicit Nominations for Project 2010-13.3 – Phase III Relay Loadability: Stable Power Swings

c. Project 2013-03 Geomagnetic Disturbance Mitigation

B. Li motioned to approve the consent agenda. F. Plett seconded the motion.


3. Projects Under Development

a. Project Tracking Spreadsheet

R. Parsons provided an overview of the spreadsheet, reporting that the spreadsheet will continue to evolve and is now posted on the standards home page on the left-hand navigation. He also noted that the spreadsheet is actively being used and there has been ongoing conversation between PMOS liaisons and standards developers regarding the status of projects and that the PMOS will review the spreadsheet at every meeting to ensure it is up to date. R. Parsons further noted that if there is a project with a “yellow” status, it is about a quarter behind the original schedule.

Several recommendations were made by Committee members and observers to improve the spreadsheet, such as ensuring all links work, adding a version date, and moving the groupings (i.e., interpretations, five-year reviews, etc) to a column. Further, it was requested that in future updates to the Committee, a report is given on projects that are behind schedule to understand why the project is behind schedule and what actions are being taken to bring the schedule back on track.

b. Standard Drafting Team Resignations

i. Project 2010-13.2 Phase 2 of Relay Loadability Resignation

ii. Project 2010-05.1 Protection System Misoperations Resignation

B. Murphy noted that two individuals resigned from the above-mentioned drafting teams and recognized their contributions to the teams.

c. Posting Projections Through July 2013

No questions were raised on this item.

4. Subcommittee Charters

B. Murphy thanked S. Miller and the subcommittees for their work on the revising the charters. S. Miller reported that he worked with the PMOS and SCPS to harmonize certain aspects of the charters


and noted that the charters all include two-year staggered terms. The charters also call for members to be selected by the subcommittee officers (appointed by the Standards Committee) and approved by the Standards Committee.

a. Task 6 of the SC Work Plan: Process Subcommittee Reforms and SCPS Charter

L. Campbell reported a small working group of the SCPS worked on the charter. The working group discussed the nature of the SCPS and felt that the group served a very important role. L. Campbell also reported that the SCPS reached out to many standard drafting team members and they felt the documentation created by the SCPS was helpful. The SCPS recommended that it continue as a subcommittee while recognizing that it should also focus on process efficiency. A revised charter was developed to support those important goals. The revised charter also states that the chair and vice chair would be appointed by the Committee and at least one officer needs to be a Committee member.

b. Project Management and Oversight Subcommittee Charter

R. Parsons presented the revised PMOS charter to the Committee for approval.

F. Plett motioned to approve the SCPS and PMOS charters. F. Gaffney seconded the motion.


After the motion, it was recommended that S. Miller put together a schedule for electing officers. It was also recommended to that the charters use the current NERC template.

5. 2013-2015 Work Plan Tasks

a. Task 2: SPM Reforms

J. Tarantino reported that a questionnaire was sent to the standard drafting team chairs and vice chairs in February 2013 regarding the standard development process. The responses to the questionnaire did not result in any common themes.

It was recommended for a new questionnaire to be sent out after the revised Standard Processes Manual is in place to determine if standard drafting teams are observing any impediments in the new processes. The exact timing of when it would be best to send out the new questionnaire was not settled, but many recommended that a significant amount of time pass prior to sending out the questionnaire.

b. Task 7: Pools of SMEs

S. Miller reported that it was more efficient to reach out to the industry as needed rather than soliciting a pool of subject matter experts.

J. Bussman motioned to endorse deferral of this task until the evaluation of the standard process enhancements during the 3rd and 4th quarter of 2013. F. Plett seconded the motion.



6. Project 2013-01 Cold Weather Preparedness SAR Recommendation

Brian Murphy introduced this item and noted that the lessons learned from the Cold Weather Preparedness SAR drafting team will be presented to the PMOS in the near future. Based on the lessons learned, the PMOS may have recommendations for future drafting teams.

Ed Schnell, the chair of the SAR drafting team, stated that he was encouraged by the newly formed PMOS and thinks it would have helped the drafting team’s efforts if they were in place earlier. He noted that a SAR was issued in September 2012 and the drafting team was formed in December 2012 to respond to comments. The drafting team created a revised SAR to bridge a small gap in EOP-001 and provided an update to the Operating Committee (OC) at its March 2013 meeting. At the same meeting, the OC approved the Generating Unit Winter Weather Readiness reliability guideline. The drafting team was subsequently notified that the OC and the Reliability Issues Steering Committee recommended that the Cold Weather Preparedness SAR should not proceed and the approved guideline should serve as the basis to address the issue. The drafting team recognized that this is the prevailing opinion of the industry and agrees with the direction.

B. Li motioned to reject the revised SAR and curtail the work on the original SAR with a written explanation to the sponsor to be posted on the NERC website. F. Plett seconded the motion.


A concern was raised regarding periodic reminders to ensure that the industry does not overlook the guideline in the future. B. Hampton noted that NERC committed to send annual reminders to the industry as a reminder of the guideline.

7. CIP Interpretation Remands

B. Murphy presented this item and noted that when a new request for interpretation is submitted, the intention is to lean towards providing clarifications to standards rather than developing an interpretation.

F. Gaffney motioned to endorse the following action items: (1) direct the SCPS to review enhancements to the interpretation approach outlined in the SPM, in light of the recent FERC remands of CIP interpretations, and to provide a recommendation on enhancements to the Committee no later than its December meeting; and (2) NERC staff to discuss with the CIP interpretation drafting team the most constructive next step in the standards process for the two recent FERC remands of CIP interpretations, with input from the chair and vice chair from the PMOS. R. Parsons seconded the motion.



8. Retire Selected Projects in the 2014-2016 RSDP

B. Murphy reported that there were a lot of proposed projects that turned into a backlog of outdated and/or duplicative projects. All projects were reviewed to determine which projects could potentially be retired based on various reasons. This review resulted in thirteen projects being proposed for retirement. This item was presented to the RISC, which supported the retirement of the projects.

J. Bussman motioned to approve the retirement of the thirteen projects listed in the background material. R. Crissman seconded the motion.

- The Committee approved the motion with no objections and one abstention (L. Campbell).

9. Volunteers to Assist with 2014-2016 RSDP

B. Murphy presented this item as a request for volunteers to work with the Committee chair, vice chair and NERC staff in developing the 2014-2016 Reliability Standards Development Plan (RSDP). He noted that the commitment would be to attend two or three meetings in Atlanta over the next few months and to be ambassadors for the RSDP. B. Hampton and C. Yeung volunteered to assist with developing the RSDP.

10. Volunteers for CCC RSAW Improvements Task Force

B. Murphy presented this item as a request for three to five volunteers to be on a Compliance and Certification Committee (CCC) RSAW Improvements team which has already been established by the CCC. Herb Schrayshuen volunteered to participate on the team.

11. Process for Election of SC Chair and Vice Chair

B. Murphy noted that the Standards Committee charter requires elections for the chair and vice chair to be held prior to the general Committee elections. Given the logistics of the Committee’s schedule meetings, the elections will be held in September for a full term chair and vice chair. The Committee discussed whether or not the chair and vice chair could vote in the election and determined that they should have a vote.

S. Rueckert motioned to approve the election process subject to the addition of a provision explicitly stating that the chair and vice chair have the right to vote in the election. F. Plett seconded the motion. (At the direction of the Committee, the election process presented to the Committee was revised to explicitly include a provision for the chair and vice chair to vote in the election. The revised election process is included as Attachment B.)


12. Balloting Process Under the Revised Standard Processes Manual

J. Bussman noted that the revised SPM (not yet approved by FERC) states that ‘no’ votes are not counted in the calculation of approval if there is no corresponding comment. He was under the


impression that the new balloting software, which is expected to handle this new requirement, would be in place by the time the revised SPM was approved.

L. Hussey stated that if the balloting software is not in place prior to the SPM being approved, NERC is prepared to manually handle the revision and will have an obligation to follow up with ‘no’ votes that appear to not have a related comment before publishing ballot results. Companies that are in multiple segments would be able to submit one set of comments that would apply to all ‘no’ votes submitted from that company. There is no intention to discount votes and all results would be publicly posted to ensure transparency.

13. Subcommittee, Task Force and Working Group Reports

a. Communication and Planning Subcommittee

M. Huggins shared the highlights of the SCCPS’s discussion from its June 4, 2013 meeting. For months, the SCCPS has been exploring different options for the future of its subcommittee, and at this meeting members aimed to draft a recommendation for the Standards Committee for the future of the subcommittee. Beginning by discussing questions about the communication functions that a stakeholder group focused on communication should serve and continuing on to a discussion of whether the SCCPS or a re-imagination of the SCCPS could serve those functions, the SCCPS developed the following four-part recommendation to the Standards Committee:

1. Add a standing item for “Communication Activities and Issues” to the agendas of the SC, Project Management and Oversight Subcommittee (PMOS), and Standards Committee Process Subcommittee (SCPS).

2. Incorporate into the SC and SCPS charters a function related to stakeholder communication and outreach.

3. Develop a roster with a pool of observers interested in providing communication feedback on an ad hoc basis on topics including but not limited to draft agendas for NERC standards workshops and webinars, changes to the Weekly Standards Bulletin, and communication tools related to specific projects.

4. Disband the SCCPS upon approval of these recommendations. M. Huggins shared this recommendation as a preview of what the SCCPS will be formally presenting to the SC for approval during its July meeting. No questions were raised.

b. Process Subcommittee

i. Revision to Rapid Revision Procedure

A. Pusztai reported that the procedure was revised and posted for comment in March. The changes made in response to the comments received were mainly for clarification and generally minor. After approval by the Committee, it would be posted as a resource document


on the NERC website. In the Rapid Revision Procedure, a SAR is still required, but the scope would be narrower than a SAR for a typical project.

F. Gaffney motioned to approve the revised Rapid Revision Procedure and post as resource document. R. Crissman seconded the motion.

- The Committee approved the motion with no objections and one abstention (K. Lambeck).

ii. Improving Consensus Building at the SAR Development Stage

D. Kiguel presented this item as a living document that elaborates on the SPM to clarify the Committee’s authority regarding assessing and approving SARs. There were a number of questions raised by Committee members and observers on the proposed process.

Based on the number of questions raised, B. Li suggested tabling the request for approval and the SCPS will refine the document to clarify the issues raised before presenting it to the Standards Committee for action. He noted that the intent of the process is to ensure that a SAR has sufficient technical justification before it is posted for industry comment.

iii. Other SCPS Activities

1. Incorporating Quality Review into Standard Drafting

K. Porterfield reported that at the last meeting, the SCPS presented options for performing quality reviews (QR) and the Committee voted to keep QR as an outside process at key points (each time a standard is first posted and beyond that it would be at the discretion of the standard drafting team). The Committee also requested that the SCPS review the scope of the QR process. The group reviewed the scope and its initial review suggests they will recommend a substantial reduction in the scope by reducing almost 50 items the QR team had to go over to certain key items.

2. Revision to Violation Risk Factor Determination

P. Heidrich reported that this item is an ongoing project to revise the VRF definitions which was initiated because definitions were never fully vetted with industry and there was confusion regarding risk versus importance. One of the SPIG recommendations was to eliminate VRFs and VSLs, but comments received on the SPM revisions were overwhelmingly supportive of keeping the VRFs and VSLs. Revisions are being developed to expand the three-tier approach to VRFs to five-tier VRFs and also create specific definitions that apply to operating, planning, and critical infrastructure standards. There is a sub-group that has reviewed the revised definitions and will need to coordinate with FERC staff, compliance and enforcement, and NERC legal. After coordinating with the necessary groups, the sub-group will bring the proposal to the SCPS before presenting it to the Standards Committee for further action.

3. “Single Portal” to Triage Requests for Clarification


G. Zito reported that the “single portal” concept began as a way to triage a request for standards clarifications. After discussions with senior leadership and others in the industry, there may be an opportunity to expand this concept to triage stakeholder questions not only related to standards. A flow chart is in the process of being developed to address the original scope and the goal is to have a draft available for Standards Committee review at its August meeting. The team will continue to work with NERC on expanding the scope and expects that it would be an incremental roll-out.

B. Murphy suggested presenting this to the RISC as an informational item.

4. Updating Drafting Team Guidelines

G. Zito reported that the existing guidelines are out of date and a small group is working on another draft. The group is also reviewing the SCPS documents on the resource documents page on the NERC website. The group expects to propose to retire unnecessary documents and revise outdated necessary documents. There is also a thought to develop a shorter reference document for standard drafting teams to use.

B. Murphy encouraged the team to work with the chair and vice chair of the PMOS so the PMOS structure can be elaborated on as necessary.

5. Trial Cost Effectiveness Analysis Process

B. Murphy stated that discussions at the May MRC meeting regarding institutionalizing CEAP are in sync with the Committee’s intentions. Standards Committee leadership will work with NERC staff to present an update to the MRC at its next meeting.

G. Zito noted that the report from the first pilot was presented at the last Standards Committee meeting. The first pilot was well received, and while it is only a first step he believes it is beneficial to stakeholders and the standards development process. A second phase of the process (cost impact) will be performed on another project soon with the goal to have a final guideline document to present to the Committee before the end of the year.

The Committee discussed how to institutionalize CEAP as part of the standards development process, as an ad hoc team is not a sustainable model. B. Murphy stated that he would coordinate this effort.

c. Project Management and Oversight Subcommittee

R. Parsons noted that the PMOS is still in start-up mode and expects to continue to receive recommendations to improve the efficiency and value of the PMOS. At the next meeting, the PMOS will review the lessons learned from the cold weather drafting team.

d. Task Force to Review Rules and Processes Related to the RBB and Eligibility to be Nominated for the SC


F. Plett reported that a task force was approved by the Standards Committee at its last meeting and presented a scope of work developed by the task force. The Committee did not raise any issues with the scope of work presented.

e. Functional Model Work Group

B. Murphy reported that the FMWG put together recommendations for the Committee regarding the future of the FMWG and its outstanding tasks which would be brought to the Committee at its July meeting.

14. Upcoming Standards Filings

Bill Edwards reported on upcoming filings and noted that NERC legal recently submitted a filing requesting an extension of time of the effective date of the definition of Bulk Electric System.

15. Informational Items

a. Standards Process Results for First Quarter 2013

b. Notice of NERC Reaccreditation under Revised Standard Processes Manual

c. SC Expectations

d. Standards Committee Roster

e. Highlights of Parliamentary Procedure

f. Schedule and Locations for 2013 Meetings

The Committee discussed changing future face-to-face meetings to one full day or two half-day meetings. It was decided that the September face-to-face meetings would be changed to one full day (Thursday only) and the December face-to-face meeting would be changed to two half-days. A two half-day meeting schedule would be considered when developing the schedule for 2014.

16. Adjourn

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Standards Committee June 5-6, 2013 Attendance List

Segment Name Company Attendance

Chairman Brian Murphy NextEra Energy, Inc. X

Vice Chairman Scott Miller MEAG Power X

Segment 1-2013-14 Lou Oberski

Ron Parsons, proxy Dominion Resources Services, Inc.

X

Segment 1-2012-13 Carol Sedewitz National Grid X

Segment 2-2013-14 Charles Yeung Southwest Power Pool X

Segment 2-2013 P.S. (Ben) Li Ben Li Associates, Inc. X

Segment 3-2013-14 Jennifer Sterling

Chris Scanlon, proxy Exelon

X

Segment 3-2012-13 John Bussman Associated Electric Cooperative Inc. X

Segment 4-2013-14 Joseph Tarantino Sacramento Municipal Utility District X

Segment 4-2012-13 Frank Gaffney Florida Municipal Power Authority X

Segment 5-2013-14 Gary Kruempel MidAmerican Energy Company X

Segment 5-2013 Randy Crissman New York Power Authority X

Segment 6-2013-14 Brenda Hampton Energy Future Holdings – Luminant Energy Company LLC

X

Segment 6-2013 Andrew Gallo

Lisa Martin, proxy City of Austin dba Austin Energy

X

Segment 7-2013-14 John A. Anderson Electricity Consumers Resource Council X

Segment 7-2012-13 Frank McElvain Siemens Energy

Segment 8-2013-14 Vacant

Segment 8-2012-13 Fred Plett Massachusetts Attorney General X

Attachment A

of 2

Segment Name Company Attendance

Segment 9-2013-14 Diane Barney New York State Public Service Commission

Segment 9-2012-13 Klaus Lambeck Ohio Public Utilities Commission X (phone)

Segment 10-2013-14 Steve Rueckert Western Electricity Coordinating Council X

Segment 10-2012-13 Linda Campbell Florida Reliability Coordinating Council X

Canada David Kiguel Hydro One Networks Inc. X

Secretary Kristin Iwanechko NERC X

BOT Members:

• Paul Barber • David Goulding • Ken Peterson

FERC Staff:

• Keith O’Neal

NERC Staff: • Howard Gugel • Mallory Huggins • Valerie Agnew • Laura Hussey

• Mark Olson • Stacey Tyrewala

A number of observers were also on the call.

Attachment B

Process for Election of Chair and Vice Chair On June 5, 2013, the Standards Committee approved the following approach for the elections of chair and vice chair of the Standards Committee to two year terms starting January 1, 2014 and ending December 31, 2015, subject to explicitly stating that the chair and vice chair have the right to vote in the elections. This revised process includes a provision explicitly stating that the chair and vice chair have the right to vote in the elections (redline and clean copy below). (REDLINE)

1. The formation of a nomination committee, consisting of the three “at large” SCEC members (i.e., John B, Fred P and Joe T). If any of these members decide to run for chair or vice chair, they shall resign from the nominating committee. If a member(s) of the nominating committee decide to run for chair or vice chair, the chair of the SC will solicit, via an email announcement, SC member(s) to serve on the nominating committee, so the nominating committee is a its full three member complement.

2. The nominating committee shall solicit nominations for chair and vice chair from June 6, 2013 to August 1, 2013, with the understanding that nominations may be selected from the floor on the day of the election pursuant to Section 5 (1) of the SC Charter. The nominating committee shall develop a questionnaire to solicit the qualifications from the nominees. Nominations may be made via another SC member or via self-nominations. Any member nominated by another SC member will be requested to confirm they accept the nomination.

3. No later than August 15, 2013, the nominating committee shall provide the SC a list (via email)

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

4. At the September 18, 2013 SC face-to-face meeting, elections for the chair and vice chair will be conducted immediately after the consent agenda is completed. The elections shall be accomplished as follows:

a. The nominating committee will ask if there are any nominations from the floor. If there is a nomination from the floor, the nominee shall be provided 5 minutes to orally present his or her qualifications to the SC.

b. After (a) is completed, the Secretary of the SC shall distribute written election ballots for both chair and vice chair. The members shall mark their selection on the ballot and provide the ballot back to the Secretary. Any SC member participating by phone shall submit his or her selections to the Secretary via email.

The chair and vice chair have the right to vote in both of the elections for chair and vice chair.

Attachment B

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

6. The term, duties and responsibilities of the elected chair and vice chair start on January 1, 2014 and end on December 31, 2015.

(CLEAN)

1. The formation of a nomination committee, consisting of the three “at large” SCEC members (i.e., John B, Fred P and Joe T). If any of these members decide to run for chair or vice chair, they shall resign from the nominating committee. If a member(s) of the nominating committee decide to run for chair or vice chair, the chair of the SC will solicit, via an email announcement, SC member(s) to serve on the nominating committee, so the nominating committee is a its full three member complement.

2. The nominating committee shall solicit nominations for chair and vice chair from June 6, 2013 to August 1, 2013, with the understanding that nominations may be selected from the floor on the day of the election pursuant to Section 5 (1) of the SC Charter. The nominating committee shall develop a questionnaire to solicit the qualifications from the nominees. Nominations may be made via another SC member or via self-nominations. Any member nominated by another SC member will be requested to confirm they accept the nomination.

3. No later than August 15, 2013, the nominating committee shall provide the SC a list (via email)

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

4. At the September 18, 2013 SC face-to-face meeting, elections for the chair and vice chair will be conducted immediately after the consent agenda is completed. The elections shall be accomplished as follows:

a. The nominating committee will ask if there are any nominations from the floor. If there is a nomination from the floor, the nominee shall be provided 5 minutes to orally present his or her qualifications to the SC.

Attachment B

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

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

5. After all written and email ballots are collected by the Secretary, the Secretary and members of

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

6. The term, duties and responsibilities of the elected chair and vice chair start on January 1, 2014 and end on December 31, 2015.

Agenda Item 4 Standards Committee

July 18, 2013

MOD B Informal Development Project Requested Action

1. Authorize the concurrent posting of the MOD B Standards Authorization Request (SAR) for a 45-day informal comment period (given it is addressing FERC directives) along with the revised MOD B reliability standards (proposed MOD-032-1 and MOD-033-1), VRFs/VSLs, and associated implementation plan for a 45-day comment period with a ballot pool formed during the first 30 days of the comment period, and a ballot and non-binding poll conducted during the last ten days of that comment period; and

2. Approve the posting for a 10-day solicitation for nominations for Standard Drafting Team members for MOD B’s formal development.

MOD B is assigned project number 2010-03. Background On February 16, 2007, FERC issued Order No. 890, Preventing Undue Discrimination and Preference in Transmission Service, and on March 16, 2007, FERC issued Order No. 693, Mandatory Reliability Standards for the Bulk-Power System. Thirteen outstanding directives remain from those two orders (1 from Order No. 890, 12 from Order No. 693), which are explained in detail in the “Informal Development Background of MOD B Standards” document contained in the SAR package. Additionally, a significant set of recommendations for improvement in MOD-010 through MOD-015 came from the NERC Planning Committee’s System Analysis and Modeling Subcommittee (SAMS). SAMS proposed several improvements to the modeling data standards in December 2012, to include consolidation of the standards, and the discussion from that whitepaper is provided in substance in the body of the SAR itself. The informal consensus building for MOD B began in February 2013. Specifically, the ad hoc group engaged stakeholders on how best to address the FERC directives, paragraph 81 criteria, and results-based approaches. A discussion of the ad hoc group’s consensus building and collaborative activities are included in the “Informal Development Background of MOD B Standards” document contained in the SAR package. Based on stakeholder outreach, the MOD B ad hoc group has developed two new proposed reliability standards that address the FERC directives and recommendations for improving MOD-010 through MOD-015, which included creating results-based requirements and considering paragraph 81 criteria to ensure that the standards proposals did not include requirements that meet those criteria. A further discussion of this topic is included in the SAR package (see pages 3 and 4 of the “Informal Development Background of MOD B Standards” document). The existing MOD-010 through MOD-015 standards are proposed to be retired, with relevant portions consolidated into a single modeling data standard in MOD-032-1, and the new validation requirements are included in a proposed new standard in MOD-033-1.


July 18, 2013 The goal is to present the MOD B standards to the NERC Board of Trustees during its November 2013 meeting, and for the Board adopted MOD-032-1 and MOD-033-1 to be filed with the applicable regulatory authorities by the end of 2013. Standard Drafting Team The MOD B drafting team is proposed to consist of a maximum of 10 members. Since this project is a continuation of informal development, several drafting team members will be selected from members of the informal group and the remainder from industry. A confidential slate of candidates with recommendations for appointment will be provided following the public solicitation. The purpose of this appointment/solicitation approach is to ensure a smooth transition from the informal to formal standards development process for MOD B, while also providing an opportunity for solicitation of new members to help provide a well-rounded perspective to moving MOD B forward. The public solicitation shall request that standard drafting team members have experience in one or more of the following areas: transmission planning, steady-state and dynamics modeling, and system model validation. The public solicitation shall also request representation from each of the Eastern, Western, and Texas interconnections, and from various organizations whose functions are contemplated to be subject to the standards. In addition, team members with experience in compliance, legal, regulatory, and technical writing are desired. Previous drafting team experience is beneficial, but not a requirement. Quality Review A quality review was coordinated by NERC staff for the posting of the MOD B reliability standard, implementation plan, VRFs and VSLs, and other associated documents. Project Schedule The drafting team is expected to facilitate meeting the proposed schedule contained in the SAR package.

MOD B SAR Package Submittal to the

NERC Standards Committee

July 18, 2013

3353 Peachtree Road NE Suite 600, North Tower

Atlanta, GA 30326 404-446-2560 | www.nerc.com

MOD B Standards Committee Package - Contents Bookmark Description

Standards Authorization

Request

An informal development ad hoc group is presenting pro forma standards addressing the outstanding directives and suggested improvements related to NERC Reliability Standards MOD-010 through MOD-015.

Pro Forma Standards

Standard MOD-032-1 is a consolidation and replacement of existing MOD-010-0, MOD -011-0, MOD-012-0, MOD-013-1, MOD-014-0, and MOD-015-0.1, and it requires a minimum level of data submission by applicable data owners to their respective Transmission Planners and Planning Coordinators to support the interconnection model building process in their interconnection. Standard MOD-033-1 is a new standard, and it requires each Planning Coordinator to implement a documented process to perform model validation within its planning area.

Compliance Input The informal ad hoc group engaged NERC Compliance for feedback and suggestions to coordinate compliance and audit considerations into the proposals’ development.

Implementation Plan

The implementation plan specifies the effective dates and initial performance expectations of MOD-032-1 and MOD-033-1, and it specifies the retirement dates of the existing MOD-010 through MOD-015 standards.

Mapping Document

The mapping document shows how the existing MOD-010 through MOD-015 standards translate to the new requirements in the MOD-032-01 and MOD-033-1 proposals. If the requirements within the existing MOD A standards do not map to a requirement, are deleted, or are otherwise represented by new concepts, an explanation is provided.

Consideration of Issues and Directives Document

The Consideration of Issues and Directives document provides a brief quotation of the relevant portion of each FERC directive that remains outstanding related to MOD-010 through MOD-015, a specific reference listing the FERC order number and specific paragraph containing the directive, and explanation of how the proposals in MOD-032-1 and MOD-033-1 address the directive.

Informal Development Background Information

The purpose of this document is to provide background and information on the informal development considerations and breadth of outreach. There is not a specific “technical white paper” provided, as the NERC Planning Committee’s System Analysis and Modeling Subcommittee (SAMS) created an extensive technical whitepaper on MOD-010 through MOD-015 proposed improvements, the majority of which has been included in substance within the SAR itself. There are also links within each standard to the SAMS whitepaper.

Proposed Timeline for the SDT

The proposed timeline for the formal development provides estimates for face to face meetings and starting and end dates for various postings, along with the Board of Trustees meeting in November and the expecting filing date by December 31, 2013.

Standards Authorization Request Form

Draft 12/2/12

1


Request to propose a new or a revision to a Reliability Standard

Title of Proposed Standard: Modification of MOD-010 through MOD-015

Date Submitted: 12/12/2012

SAR Requester Information

Name: John Simonelli, Chair, on behalf of the System Analysis and Modeling Subcommittee

Organization: System Analysis and Modeling Subcommittee

Telephone: 404-357-9843 E-mail: [email protected]

SAR Type (Check as many as applicable)

New Standard

Revision to existing Standard

Withdrawal of existing Standard

Urgent Action

SAR Information

Purpose (Describe what the standard action will achieve in support of Bulk Electric System reliability):

This SAR proposes modifying the current standards MOD-010 through MOD-015 by combining them into

a fewer number of standards. This project will resolve FERC Order No. 693 directives relating to MOD-10

through MOD-15. The combined standards should be improved and strengthened to include additional

requirements for the supply of data and models that specify the responsible functional entities, criteria

for acceptability, standard formatting, and shareability. Short circuit data requirements should also be

added to support the latest draft of the TPL-001-2 standard.

Industry Need (What is the industry problem this request is trying to solve?):

Models are the foundation of virtually all power system studies. Calculation of operating limits, planning

studies for assessment of new generation and load growth, and performance assessments of system

integrity protection schemes are but some of the studies that depend on accurate mathematical

representations of transmission, generation, and load.

The current standards have several limitations in three broad categories that should be addressed:


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2

SAR Information

Needed MOD standards are not approved o MOD-011, MOD-013, MOD-014 and MOD-015 were not approved by FERC Order No. 693

and remain in “pending” state due to their “fill-in-the-blank” nature, with requirements applicable to Regional Reliability Organizations (RROs).

o Approved standards MOD-010 and MOD-012 refer to specific modeling needs and processes outlined in unapproved standards MOD-011 and MOD-013 respectively.

Approved MOD standards require clarification o The approved MOD standards lack clear delineation of responsibilities for providing and

receiving needed data and models. o The approved standards lack specificity. For example, the standards do not describe the

quality and usability that the provided models must have for static and dynamic conditions.

The MOD standards should be strengthened o Newer Reliability Standards such as TPL-001-2 require a level of modeling not supported

by the approved MOD standards. o The approved standards do not support the increased modeling demands of new

technologies (e.g., renewable resources). o The absence of cogent modeling standards makes it difficult to identify the source of

emerging Interconnection-wide issues (such as declining frequency response), and to perform event analysis for large system disturbances.

Furthermore, the Power System Model Validation White Paper by the NERC Model Validation Task Force

(MVTF) of the Transmission Issues Subcommittee (TIS) recommended that “The NERC MOD standards on

powerflow and dynamics data (MOD-010 through MOD-015) should be improved and strengthened.”

Brief Description (Provide a paragraph that describes the scope of this standard action.)

1. The quantity of MOD standards should be reduced by combining the existing standards MOD-

010 through MOD-015 into a fewer number of standards (such as one for steady state and one

for dynamics).

2. Short Circuit Data requirements should be added to support the latest draft of the TPL standard

(TPL-001-2).

3. Additions should be made to the requirements to supply data and models.

a. The correct functional entities that are responsible to provide data and models or receive

them should be identified. References to the RRO as the applicable entity should be

removed from any existing or new requirements.

b. Criteria for acceptability should be identified for supplied data and models.

c. A standard format should be specified for supplied data.


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3

SAR Information

d. New technology model requirements should be included.

e. Shareability of proprietary models should be addressed.

Detailed Description (Provide a description of the proposed project with sufficient details for the

standard drafting team to execute the SAR. Also provide a justification for the development or revision

of the standard, including an assessment of the reliability and market interface impacts of implementing

or not implementing the standard action.)

All devices and equipment attached to the electric grid must be modeled to accurately capture how that

equipment performs under static and dynamic conditions. There have been issues with proprietary

models and the ability to share across sectors. Many generator manufacturers, notably wind turbine

manufacturers, wish to keep the dynamics properties of their equipment confidential. As most areas are

experiencing a surge in wind penetration, obtaining accurate dynamics model data for wind farms is

becoming increasingly difficult, if not impossible. Similar challenges are also associated with modeling of

utility-grade photovoltaic installations.

Generator Owners must provide accurate model data of their systems during the interconnection

process. This information is critical to ensure that their power generating systems can be safely

integrated into the electric grid. However, many of those accurate model datasets submitted for use in

the interconnection process cannot be used for any other modeling endeavors due to non-disclosure

agreements or pro forma tariff language concerning use of confidential information. These generator

owners state that industry sensitive data is contained in their datasets and therefore cannot be divulged

to anyone outside the interconnecting utility. This precludes use of those data and models in

Interconnection-wide powerflow and dynamic analysis, which is crucial to understanding how the

connecting equipment will interact with the rest of the system. Similar situations are arising with the

models for wind turbines, photovoltaic inverters, and other power electronic devices.

When a number of proprietary models are excluded from system analysis, the interconnection-wide

model becomes incomplete, and the potential interaction of equipment and their control systems is

unknown. As such, there is no way to analyze the potential operating conditions of the interconnection.

Several improvements to MOD-010 through MOD-015 are outlined below. The standards development

process will naturally need to consider parallel developments in other projects (such as Project 2007-09

Generator Verification) as well as requirements in other existing standards (such as IRO-010-1a and TOP-

003-2). It may be desirable to move modeling requirements from other standards into the revised MOD

standards. Furthermore, industry best practices and existing processes should be considered in the

development of requirements, as many entities are successfully coordinating their efforts.


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4

SAR Information

1. Reduce the quantity of MOD Standards

MOD-010 through MOD-015 should be combined into a fewer number of standards, such as one

standard for steady state and one for dynamics. However, it may also be useful to develop separate

standards for equipment data collection (for the purpose of building needed steady-state and dynamic

models) and the construction and validation of solved cases. MOD-011 and MOD-013 could be

eliminated, but needed requirements from these standards should be moved into MOD-010 and MOD-

012 respectively (or a comparable standard or set of standards).

MOD-010-0 clearly states that responsible entities (including Transmission Owners, Transmission

Planners, Generator Owners, and Resource Planners) must provide the needed steady state data and

models in accordance with requirements that are provided in MOD-011-0. If MOD-011-0 is eliminated,

then MOD-011-0 R1.1 through R1.7 must be included in a revised MOD-010 (or comparable standard).

Further, a revised MOD-010 must include requirements for Planning Coordinators and Reliability

Coordinators to provide the needed data, models and assembled cases to the Regional Entities and ERO

(upon request or on a schedule) to facilitate the development of Interconnection-wide steady-state

modeling cases.

MOD-012-0 contains requirements that responsible entities (including Transmission Owners,

Transmission Planners, Generator Owners, and Resource Planners) shall provide appropriate equipment

characteristics, system data, and dynamics system modeling and simulation data in compliance with the

respective Interconnection-wide requirements and reporting procedures. Further, the standard requires

that the responsible entities must have evidence that they complied with the Interconnection-wide

requirements and reporting procedures.

MOD-012-0 also states that the responsible entities (including Generator Owners) must provide the

needed data and models in accordance with requirements that are provided in MOD-013. If MOD-013 is

eliminated, then the specifics provided in MOD-013-1 R1.1, R1.2, R1.3, R1.4, and R1.5 must be included

in MOD-012. Further, MOD-012 must include requirements for Planning Coordinators and Reliability

Coordinators to provide the needed data, models and assembled cases to the Regional Entities and ERO

(upon request or on a schedule) to facilitate the development of Interconnection-wide dynamics

modeling cases.

A revised MOD-012 (or comparable standard) should account for the current MOD-013-1 provision that

allows for responsible entities to provide estimated or typical manufacturer dynamics data based upon


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SAR Information

criteria provided in the Interconnection-wide procedures.1 A comparable provision should be included in

a revised standard, but the requirements should be strengthened by specifying (and limiting) the

instances when generic manufacturer data is accepted. For example, estimated or typical data could be

accepted on a temporary basis, or upon documented agreement between entities when the impact is

shown to be negligible; however, it is not possible to determine the impact without a sufficient model. A

stronger, FERC-approved standard could ultimately resolve some of the issues associated with the use of

generic manufacturer data for equipment, including wind turbines.

2. Add Short Circuit Data to MOD Standards

Short circuit analysis is required in the approved FAC-002-1 standard and the latest draft of the TPL-001-

2 standard.2 While the development of Interconnection-wide short-circuit modeling cases is not

necessary and should not be required in a standard, the standards must require that neighboring entities

share a sufficient level of short-circuit data to enable the studies required by the existing and future

standards.

3. Add to the Requirement to Supply Data and Models a. Identify responsibility to provide and identify who is responsible to receive

A model of the power system requires data that includes but is not limited to: loads, transmission lines,

transformers, shunt devices, generators, stacking order for dispatching generators, and interchanges of

power. Such data must be supplied by various functional entities as shown in the table below. This data

must be supplied to Planning Coordinators, Transmission Planners, Transmission Operators, and

Reliability Coordinators as applicable. The Planning Coordinator or Transmission Planner should be

responsible for putting all of the data together in a power flow case with associated dynamics data.

These assembled cases should then be supplied to the Regional Entities and ERO, who can then combine

cases to develop an Interconnection-wide case.

1 MOD-013-1 R1.2.1 states: “Estimated or typical manufacturer’s dynamics data, based on units of similar design

and characteristics, may be submitted when unit-specific dynamics data cannot be obtained. In no case shall other than unit-specific data be reported for generator units installed after 1990.”

2 See FAC-002-1 R1.1.4 and TPL-001-2 R2.3 & R2.8. See also page 209 in Project 2010-03 Modeling Data.


Draft 12/2/12

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SAR Information

Table 2: Data Responsibilities

Data

Responsible

for Providing

Data & Models Delivers To

Load Forecast LSE PC, TP, TOP, RC

Transmission Data TO PC, TP, TOP, RC

Generator Data GO PC, TP, TOP, RC

a. Resource Projections

b. Generation stacking order RP PC, TP, TOP, RC

Interchange TSP, BA PC, TP, TOP, RC

Complete cases/models PC, TP ERO, RE

b. Identify acceptability

The present MOD standards provide little to no specification on whether a particular set of model data

meets the requirements of the standards. The group recommends the following changes to the

standards to identify acceptability:

For powerflow models, the standards should specifically list all of the parameters which must be provided. For some parameters, it may be desirable to include established norms (for example, a typical range for transmission line impedance per mile at a given voltage). For these parameters, the data should either conform to established norms, or a statement attesting to unusual values should be provided. Data for new equipment should be tested in a standard library powerflow case by performing a solution to test convergence and reasonableness. Model data for a particular piece of equipment should be consistent across all applications that use that data. When available, the model data for the equipment should be from vendor-certified test reports or field tests. If a novel device is required to be represented by a user-written model, the standards should mandate that all of the equations describing the characteristics and logic of the model must be provided, along with any other descriptive information. Additionally, the data provided by asset owners needs to meet model validation standards such as MOD-026 and MOD-027 and any additional standards that arise from the work of the NERC Model Validation Working Group (MVWG).


Draft 12/2/12

7

SAR Information

For dynamics models, a standard, industry-recognized model name and a set of parameter values must be provided. If a standard, industry-recognized model is not available, the standards should specify that the asset owner must provide a block diagram, equations describing the characteristics of the model, values and names for all model parameters, and a list of all state variables. Furthermore, it should be required that, if a standard model is not available, the owner should develop the non-standard model in the format needed by the Transmission Planner or Planning Coordinator. The standards also need to specify that this information will be shared on an Interconnection-wide basis. Proprietary models with details hidden from the user (“black box”

models) or those models that cannot be shared across the Interconnection are not acceptable.3 Engineers performing power system studies need access to all of the model information in order to properly analyze the reliability and operating characteristics of the power system. To the extent practical, the revised MOD standards should include a list of specific data that is required. Preference should be given to IEEE standard models where such models are suitable representations of the equipment being modeled. Additionally, the data provided by asset owners needs to meet model validation standards such as MOD-026 and MOD-027 and any additional standards that arise from the work of the NERC MVWG.

The standards must also specify that the asset owner will provide models with additional detail and specificity to any Planning Coordinator upon request for its own internal studies.

c. Standard format

The specification and use of a standard format or set of formats enables data to be exchanged easily

between involved entities (e.g., PCs, TPs, TOPs, RCs, TOs, GOs, LSEs, RPs) and helps support the accurate

development of steady state, short circuit, and dynamic base cases. Having a standard format allows the

development and aggregation of base cases which cover large areas such as the four Interconnections in

North America. Each vendor has their own data format, some of which are translatable between

vendors. However, some translations are only useful for steady-state analysis. Dynamics data does not

translate well between vendors.

The MOD standards should incorporate industry standard formats for all steady-state, short-circuit, and

dynamics data, and the standard formats should be approved via the NERC standard development

process. A translation of a specific vendor format to the common format is acceptable provided the

resulting data has been validated.

3

As noted in Section 1 and footnote 1, concessions could be considered for the acceptance of generic manufacturer data, if proven to be working and useful, based on whether it is used on a temporary basis or when the impact is shown to be negligible, for example.


Draft 12/2/12

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SAR Information

NERC should lead the development of test cases to validate the translation of the vendor format to the

common format. If a specific vendor format is not translatable to the approved common format then it

does not comply with the standard. Coding for generic block diagrams should be included. The NERC

Model Validation Working Group also recommends standardizing data exchange formats.

d. How to deal with new technology (require a user-written model if no standard model exists)

Presently, models for new technology equipment are introduced in a non-uniform manner. Equipment

manufacturers and other outside interests have internally created a proliferation of non-standard

equipment models. These models thus lack sufficient input from the individuals who study reliability and

operating characteristics of the power system. These models were inserted into production studies

without vetting from recognized technical authorities such as the IEEE. Many of these models are

proprietary and distributed as “black box” object code modules for specific simulation programs.

Models for new technology must include information comparable to existing models in common use.

Powerflow models need to include the equations describing the characteristics of the equipment being

modeled. For dynamics, a block diagram is essential. Ideally, the industry should collaboratively develop

model structures which include those elements that are of importance in power system studies. Such an

effort would enable consistent development of useful models while simultaneously protecting

manufacturer interests regarding confidential trade secrets of implementation details that are not

relevant to power system studies. Equipment should not be allowed to connect to the grid if the models

lack the information needed for performing appropriate reliability and operating characteristics

assessments. All responsible entities including Transmission Owners and Generator Owners must be held

accountable for providing the information needed to maintain power system reliability.

e. Shareability (an issue tangential to the MOD standards)

One of the problems identified in the Power System Model Validation White Paper is that there are legal

and procedural issues that inhibit the gathering and distribution of model data among stakeholders. The

report cites FERC CEII (critical energy infrastructure information) requirements and proprietary issues

that result in claims of the need for confidentially.

The report noted that in particular, Generator Owners of wind turbines are unable to provide unit

specific data due to wind turbine manufacturer statements that the dynamics models of their equipment

must be held confidential. This is particularly problematic in areas that are experiencing a surge in wind

penetration.


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9

SAR Information

One possible approach to address proprietary model issues is for the Generator Owner to work with the

vendor to develop a generic model that can be shared across the Interconnection. In such a case, the

standard should specify that the Generator Owner is responsible for reviewing and submitting

supporting simulations performed by the vendor that demonstrate and certify a provided generic model

will accurately simulate the generator (or any other device in question) for system level studies. The

Generator Owner must also arrange to give the proprietary model to the Transmission Planner, Planning

Coordinator, and Reliability Coordinator for their sole use, using an NDA if necessary.

Another approach is for NERC and/or FERC to hold a technical conference where wind turbine

manufacturers will be asked to give explanations for keeping their models proprietary while NERC staff

and members of NERC subcommittees describe why detailed models are required. Following such a

technical conference, NERC and FERC could consider subsequent steps that could result in a FERC Notice

of Inquiry or Notice of Proposed Rulemaking on the subject.

Reliability Functions

The Standard will Apply to the Following Functions (Check each one that applies.)

Regional Reliability

Organization

Conducts the regional activities related to planning and operations, and

coordinates activities of Responsible Entities to secure the reliability of

the Bulk Electric System within the region and adjacent regions.

Reliability Coordinator

Responsible for the real-time operating reliability of its Reliability

Coordinator Area in coordination with its neighboring Reliability

Coordinator’s wide area view.

Balancing Authority

Integrates resource plans ahead of time, and maintains load-

interchange-resource balance within a Balancing Authority Area and

supports Interconnection frequency in real time.

Interchange Authority

Ensures communication of interchange transactions for reliability

evaluation purposes and coordinates implementation of valid and

balanced interchange schedules between Balancing Authority Areas.

Planning Coordinator Assesses the longer-term reliability of its Planning Coordinator Area.

Resource Planner Develops a >one year plan for the resource adequacy of its specific loads

within a Planning Coordinator area.


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Transmission Planner Develops a >one year plan for the reliability of the interconnected Bulk

Electric System within its portion of the Planning Coordinator area.

Transmission Service

Provider

Administers the transmission tariff and provides transmission services

under applicable transmission service agreements (e.g., the pro forma

tariff).

Transmission Owner Owns and maintains transmission facilities.

Transmission

Operator

Ensures the real-time operating reliability of the transmission assets

within a Transmission Operator Area.

Distribution Provider Delivers electrical energy to the End-use customer.

Generator Owner Owns and maintains generation facilities.

Generator Operator Operates generation unit(s) to provide real and Reactive Power.

Purchasing-Selling

Entity

Purchases or sells energy, capacity, and necessary reliability-related

services as required.

Market Operator Interface point for reliability functions with commercial functions.

Load-Serving Entity Secures energy and transmission service (and reliability-related services)

to serve the End-use Customer.

Reliability and Market Interface Principles

Applicable Reliability Principles (Check all that apply).

1. Interconnected bulk power systems shall be planned and operated in a coordinated manner

to perform reliably under normal and abnormal conditions as defined in the NERC Standards.

2. The frequency and voltage of interconnected bulk power systems shall be controlled within

defined limits through the balancing of real and Reactive Power supply and demand.

3. Information necessary for the planning and operation of interconnected bulk power systems

shall be made available to those entities responsible for planning and operating the systems reliably.

4. Plans for emergency operation and system restoration of interconnected bulk power systems

shall be developed, coordinated, maintained and implemented.

5. Facilities for communication, monitoring and control shall be provided, used and maintained

for the reliability of interconnected bulk power systems.


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11


6. Personnel responsible for planning and operating interconnected bulk power systems shall be

trained, qualified, and have the responsibility and authority to implement actions.

7. The security of the interconnected bulk power systems shall be assessed, monitored and

maintained on a wide area basis.

8. Bulk power systems shall be protected from malicious physical or cyber attacks.

Does the proposed Standard comply with all of the following Market Interface

Principles?

Enter

(yes/no)

1. A reliability standard shall not give any market participant an unfair competitive advantage.

Yes

2. A reliability standard shall neither mandate nor prohibit any specific market structure.

Yes

3. A reliability standard shall not preclude market solutions to achieving compliance with that standard.

Yes

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

Related Standards

Standard No. Explanation

IRO-010-1a Identifies the high-level process that must be followed to ensure that RCs are

provided with models. This standard could be considered for consolidation into

revised MOD standards.

TOP-003-2 Identifies the high-level process that must be followed to ensure that BAs and

TOPs are provided with models. This standard could be considered for

consolidation into revised MOD standards.


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Related SARs

SAR ID Explanation

Regional Variances

Region Explanation

ERCOT

FRCC

MRO

NPCC

RFC

SERC

SPP

WECC

MOD-032-1 — Data for Power System Modeling and Analysis

July 9, 2013 Page 1 of 23

Standard Development Timeline

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. SAR posted for comment (Dates of posting TBD).

Description of Current Draft

This is the first posting of this standard for a 45-day formal comment period and initial ballot. Several directives remain outstanding (including from FERC Order No. 693) that relate to MOD-010 through MOD-015. This standard and Standard MOD-033-1 seek to address the outstanding directives while simultaneously incorporating recommendations for improvement from the NERC Planning Committee’s System Analysis and Modeling Subcommittee (SAMS).

Anticipated Actions Anticipated Date

Post SAR July 2013

45-day Formal Comment Period with Parallel Initial Ballot July 2013

Recirculation ballot September 2013

BOT adoption November 2013



Effective Dates

In those jurisdictions where regulatory approval is required, Requirements R1 and R2 shall become effective on the first day of the fourth calendar quarter after applicable regulatory approval or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities, and Requirements R3, R4, and R5 shall become effective on the first day of the eighth calendar quarter after applicable regulatory approval or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities. In those jurisdictions where no regulatory approval is required, this standard shall become effective on the first day of the fourth calendar quarter after Board of Trustees approval, and Requirements R3, R4, and R5 shall become effective on the first day of the eighth calendar quarter after Board of Trustees approval.

Version History

Version Date Action Change Tracking

1 TBD Developed to consolidate and replace MOD-010-0, MOD -011-0, MOD-012-0, MOD-013-1, MOD-014-0, and MOD-015-0.1



Definitions of Terms Used in Standard

None



When this standard has received ballot approval, the text boxes will be moved to the Application Guidelines Section of the Standard.

A. Introduction

1. Title: Data for Power System Modeling and Analysis

2. Number: MOD-032-1

3. Purpose: To establish consistent modeling data requirements and reporting procedures to support analysis of the reliability of the interconnected transmission system.

4. Applicability:

4.1. Functional Entities:

4.1.1 Balancing Authorities

4.1.2 Generator Owners

4.1.3 Load Serving Entity

4.1.4 Planning Coordinators

4.1.5 Resource Planners

4.1.6 Transmission Owners

4.1.7 Transmission Planners

4.1.8 Transmission Service Providers

5. Background:

MOD-032-1 exists in conjunction with MOD-033-1, both of which are related to system-level modeling and validation. Standard MOD-032-1 is a consolidation and replacement of existing MOD-010-0, MOD -011-0, MOD-012-0, MOD-013-1, MOD-014-0, and MOD-015-0.1, and it requires a minimum level of data submission by applicable data owners to their respective Transmission Planners and Planning Coordinators to support the interconnection model building process in their interconnection. Standard MOD-033-1 is a new standard, and it requires each Planning Coordinator to implement a documented process to perform model validation within its planning area.

The transition and focus of responsibility upon the Planning Coordinator function in both standards are driven by several recommendations and FERC directives (to include several remaining directives from FERC Order No. 693), which are discussed in greater detail in the rationale sections of the standards. One of the most recent and significant set of recommendations came from the NERC Planning Committee’s System Analysis and Modeling Subcommittee (SAMS). SAMS proposed several improvements to the modeling data standards, to include consolidation of the



standards (that whitepaper is available from the December 2012 NERC Planning Committee’s agenda package, item 3.4, beginning on page 99, here: http://www.nerc.com/comm/PC/Agendas%20Highlights%20and%20Minutes%20DL/2012/2012_Dec_PC%20Agenda.pdf).

B. Requirements and Measures

Rationale for R1:

This requirement consolidates the concepts from the original data requirements from MOD-011-0, Requirement R1, and MOD-013-0, Requirement R1. The original requirements specified types of steady-state and dynamics data necessary to model and analyze the steady state conditions and dynamic behavior or response within each Interconnection. The original requirements, however, did not account for the collection of short-circuit data also required to perform short-circuit studies. The addition of short-circuit data also addresses the outstanding directive from FERC Order No. 890, paragraph 290.

In attempting to develop a performance-based standard that would address the data requirements and reporting procedures for model data, the MOD B informal standard development group found that it was prohibitively difficult to account for all of the detailed technical concerns associated with the preparation and submittal of model data given that many of these concerns are dependent upon evolving industry modeling needs and software vendor terminology and product capabilities.

This requirement establishes the Planning Coordinator as the developer of technical model data requirements and reporting procedures to be followed by the data owners in its planning area. The inclusion of the Transmission Planners in the applicability is intended to ensure that the Transmission Planners are able to participate in the development of the data requirements and reporting procedures.

The requirement parts of Requirement R1 list the minimum set of items that must be included in the data requirements and reporting procedures developed by the Planning Coordinator.

Coordination between Planning Coordinators in the development of these requirements and reporting procedures is necessary in order to facilitate development of interconnection-wide models. While Requirement R1 does not require this coordination, Requirement R5 includes a requirement for the Planning Coordinators to submit model data for interconnection model building in the format specified by the ERO or its designee. It would likely be most efficient for Planning Coordinators to fashion their data requirements and reporting procedures with the interconnection-wide common format in mind.

(Rationale continued on next page)

http://www.nerc.com/comm/PC/Agendas%20Highlights%20and%20Minutes%20DL/2012/2012_Dec_PC%20Agenda.pdf




Rationale for R1: Continued

This requirement is also consistent with the recommendations from the NERC System Analysis and Modeling Subcommittee (SAMS) White Paper titled “Proposed Improvements for NERC MOD Standards”, available from the December 2012 NERC Planning Committee’s agenda package, item 3.4, beginning on page 99, here: http://www.nerc.com/comm/PC/Agendas%20Highlights%20and%20Minutes%20DL/2012/2

012_Dec_PC%20Agenda.pdf.

Aside from recommendations in support of strengthening and improving MOD-010 through MOD-015, the SAMS paper included the following suggested improvements:

1) reduce the quantity of MOD standards; 2) add short circuit data as a requirement to the MOD standards; and 3) supply data and models:

a. add requirement identifying who provides and who receives data; b. identify acceptability; c. standard format; d. how to deal with new technologies (user written models if no standard model

exists); and e. shareability.

These suggested improvements in the proposed approach are addressed by combining the existing standards into two new standards, one standard for the submission and collection of data, and one for the validation of the models. Adding the requirement for the submittal of short circuit data is also an improvement from the existing standards, and the collection of short-circuit data is also consistent with FERC Order 890, paragraph 290. In supplying data, the approach clearly identifies what data is required and which Functional Entity is required to provide the data.

Data submitted to effectively model a transmission system is typically on a per-element(s) basis as the transmission system evolves. Therefore, the submittal of data, and the checking of data, is much simplified by submitting all parameters describing a specific element simultaneously, thus reducing the possibility for error in the data. Typically all data in some shape or form consists of steady-state, dynamic, and short-circuit related data and is used for these types of analysis.

The approach for the collection of data is done using an attachment approach. The attachment specifically lists the Responsible Entities that are required to provide each type of data and the data that is required. This attachment takes an “at-a-minimum” approach for the collection of data needed for the construction of the models specific to seasonal cases and specific cases and scenario and for an interconnection wide model that is not software specific. It includes data for steady-state, dynamics and short circuit. It clearly holds the Responsible Entities that have the data accountable for providing data.

Finally, the decision to combine steady-state, dynamics, and short circuit data requirements into one requirement rather than three reflects that they all support the requirement of submission of data in general.





R1. Each Planning Coordinator, in conjunction with each of its Transmission Planners, shall develop steady-state, dynamics, and short circuit modeling data requirements and reporting procedures for its planning area, including: [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]

1.1. Specification of the required data that includes, at a minimum, the data listed in Attachment 1;

1.2. Specification of the data format;

1.3. Specification that the data must be shareable on an interconnection-basis to support use in the interconnection models;

1.4. Specification of the level of detail to which equipment shall be modeled;

1.5. Specification of the case types or scenarios to be modeled; and

1.6. A schedule for submission or confirmation of data at least once every 13 calendar months.

M1. Examples of evidence include, but are not limited to, dated documentation or records that the required modeling data requirements and reporting procedures meet the specifications in Requirement R1.

R2. Each Planning Coordinator shall provide its data requirements and reporting procedures developed under Requirement R1 to any Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, Transmission Owner, or Transmission Service Provider in its planning area within 30 calendar days of a written request for the data requirements and reporting procedures. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

M2. Each Planning Coordinator shall provide evidence, such as email records or postal receipts showing recipient and date, that it has distributed the requested data requirements and reporting procedures within 30 days of receiving a written request in accordance with Requirement R2; or a statement by the Planning Coordinator that it has not received a request for its data requirements and reporting procedures.

Rationale for R2:

An entity responsible for providing data under Requirement R3 has an obligation to submit data according to the data requirements and reporting procedures in its planning area developed under Requirement R1, and there may be cases, such as change of ownership, etc., that the submitting entity would need to request a copy of the data requirements and reporting procedures from its Planning Coordinator. This requirement ensures that the data requirements and reporting procedures developed under Requirement R1 by each Planning Coordinator are made available to an entity responsible for providing such data under Requirement R3.



R3. Each Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, Transmission Owner, and Transmission Service Provider shall provide steady-state, dynamics, and short circuit modeling data to its Transmission Planner(s) and Planning Coordinator(s) according to the data requirements and reporting procedures developed by its Planning Coordinator in Requirement R1. For data that has not changed since the last submission, a written confirmation that the data has not changed is sufficient. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

M3. Examples of evidence include, but are not limited to, dated documentation or records of submission by a registered entity of the required data (to its Transmission Planner(s) and Planning Coordinator(s); or written confirmation that the data has not changed.

Rationale for R3:

The approach in this requirement to submit data to the Planning Coordinator satisfies the directive from FERC Order No. 693, paragraph 1155, which directs that “the planning authority should be included in this Reliability Standard because the planning authority is the entity responsible for the coordination and integration of transmission facilities and resource plans, as well as one of the entities responsible for the integrity and consistency of the data.”

It also accounts for areas where a BA may have more than one PC. It does not create a requirement for the PC or TP, as entities receiving data. It does, however, allow for instances where a TP may serve only as a conduit for the collection of data on behalf of functional entities if all parties mutually agree. The Responsible Entity required to supply the data in those cases is still accountable for the obligation to provide the data. In those instances, the intent of the requirement is not to change those established processes, but to reinforce and emphasize accountability for data provided by those entities that are in the best position to have correct data.



R4. Upon delivery of written notification from its Planning Coordinator or Transmission Planner regarding technical concerns with the data submitted under Requirement R3, including the technical basis or reason for the technical concerns, each notified Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, Transmission Owner, or Transmission Service Provider shall respond to the notifying Planning Coordinator or Transmission Planner as follows: [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]

4.1. Provide either updated data or an explanation with a technical basis for maintaining the current data;

4.2. If requested by the notifying Planning Coordinator or Transmission Planner, provide additional dynamics data describing the characteristics of the model, including block diagrams, values and names for all model parameters, and a list of all state variables; and

4.3. Provide the response within 30 calendar days, unless a longer time period is agreed upon by the notifying Planning Coordinator or Transmission Planner.

M4. Examples of evidence include, but are not limited to: dated records of a written request from the Transmission Planner or Planning Coordinator notifying a Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, Transmission Owner, or Transmission Service Provider regarding technical concerns, and additional evidence demonstrating the response to the request by the notified registered entity meets the specifications of Requirement R4; or a statement by the Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, Transmission Owner, or Transmission Service Provider that it has not received notification regarding technical concerns with the data submitted.

Rationale for R4: In order to maintain a certain level of accuracy in the representation of a power system, the data that is submitted must be correct, periodically checked, and updated. Data used to perform power flow, dynamics, and short-circuit studies can change, for example, as a result of new planned transmission construction (in comparison to as-built information) or changes performed during the restoration of the transmission network due to weather-related events. One set of data that changes on a more frequent basis is load data, and updates to load data are needed when new improved forecasts are created.

This requirement provides a mechanism for the PC and TP (that does not exist in the current standards) to collect corrected data from the entities that have the data. It provides a feedback loop to address technical concerns related to the data when the PC or TP identifies technical concerns, such as concerns about the usability of data or simply that the data is not in the correct format and cannot be used. The requirement also establishes a time-frame for response to address timeliness.


July 9, 2013 Page 10 of 23

R5. Each Planning Coordinator must submit the data provided to it under Requirement R3 to the ERO or its designee to support creation of the interconnection model(s) that includes the Planning Coordinator’s planning area as follows: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

5.1. In the format and according to the schedule specified by the ERO or its designee; and

5.2. Include documentation and reasons for data modifications, if any.

M5. Examples of evidence may include, but are not limited to, dated documentation or records indicating data submission from the Planning Coordinator to the ERO or its designee according to Requirement R5.

Rationale for R5: This requirement will replace MOD-014 and MOD-015

It recognizes the differences among interconnections in model building processes, but creates an obligation for PCs to provide the data in a manner that accounts for those differences.

The requirement creates a clear expectation that PCs will provide data that they collect under Requirement R3 in support of their respective interconnection models. While different entities in each of the three interconnections create the interconnection models, the requirement to submit the data to the “ERO or its designee” supports a framework whereby NERC, in collaboration with other organizations, can designate the appropriate organizations in each interconnection to build the interconnection-specific model. It does not prescribe a specific group or process to build the larger Interconnection models, but only requires the PCs to submit data in support of their creation, consistent with the SAMS Proposed Improvements to NERC MOD Standards (at page 3) that, “industry best practices and existing processes should be considered in the development of requirements, as many entities are successfully coordinating their efforts.” (Emphasis added).

For example, under current practice, the Eastern Interconnection Reliability Assessment Group (ERAG) builds the Eastern Interconnection models, the Western Electricity Coordinating Council (WECC) builds the Western Interconnection models, and the Electric Reliability Council of Texas (ERCOT) builds the Texas Interconnection models. This requirement does not require a change to that construct, and, assuming continued agreement by those organizations, ERAG, WECC, and ERCOT could be the “designee” for each interconnection contemplated by this requirement. Similarly, the requirement does not prohibit transition, and the requirement remains for the Planning Coordinators to provide the information to the ERO or to whomever the ERO has coordinated with and designated as the recipient of such information for purposes of creation of each of the Interconnection models.


July 9, 2013 Page 11 of 23

C. Compliance

1. Compliance Monitoring Process

1.1. Compliance Enforcement Authority

Regional Entity

1.2. Evidence Retention

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

The Responsible Entity shall keep data or evidence to show compliance as identified below unless directed by its CEA to retain specific evidence for a longer period of time as part of an investigation:

Each Responsible Entity shall retain evidence of each requirement in this standard for three calendar years.

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

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

1.3. Compliance Monitoring and Assessment Processes:

Compliance Audits

Self-Certifications

Spot Checking

Compliance Violation Investigations

Self-Reporting

Complaints Text

1.4. Additional Compliance Information

None

July 9, 2013 Page 12 of 23

Table of Compliance Elements

R # Time Horizon VRF Violation Severity Levels

Lower VSL Moderate VSL High VSL Severe VSL

R1 Long-term Planning

Lower The Planning Coordinator developed steady-state, dynamics, and short circuit modeling data requirements and reporting procedures, but failed to include less than or equal to 25% of the required components specified in Requirement R1.

The Planning Coordinator developed steady-state, dynamics, and short circuit modeling data requirements and reporting procedures, but failed to include greater than 25% or less than or equal to 50% of the required components specified in Requirement R1.

The Planning Coordinator developed steady-state, dynamics, and short circuit modeling data requirements and reporting procedures, but failed to include greater than 50% or less than or equal to 75% of the required components specified in Requirement R1.

The Planning Coordinator did not develop any steady-state, dynamics, and short circuit modeling data requirements and reporting procedures required by Requirement R1

OR

The Planning Coordinator developed steady-state, dynamics, and short circuit modeling data requirements and reporting procedures, but failed to include greater than 75% of the required components specified in Requirement R1.


Medium The Planning Coordinator failed to

The Planning Coordinator failed to



July 9, 2013 Page 13 of 23

provide its data requirements and reporting procedures according to Requirement R2 within 30 calendar days of a written request but did provide them within 45 calendar days.

provide its data requirements and reporting procedures according to Requirement R2 within 30 calendar days of a written request but did provide them within greater than 45 calendar days but less than or equal to 60 calendar days.

provide its data requirements and reporting procedures according to Requirement R2 within 30 calendar days of a written request but did provide them within greater than 60 calendar days but less than or equal to 75 calendar days.

provide its data requirements and reporting procedures according to Requirement R2 within 30 calendar days of a written request or did provide in greater than 75 calendar days.


Medium The Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, or Transmission Service Provider provided steady-state, dynamics, and short circuit modeling data to its Transmission Planner(s) and Planning Coordinator(s), but failed to provide less than or equal to 25% of the required data specified in

The Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, or Transmission Service Provider provided steady-state, dynamics, and short circuit modeling data to its Transmission Planner(s) and Planning Coordinator(s), but failed to provide greater than 25% but less than or equal to 50% of the required data specified in

The Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, or Transmission Service Provider provided steady-state, dynamics, and short circuit modeling data to its Transmission Planner(s) and Planning Coordinator(s), but failed to provide greater than 50% but less than or equal to 75% of the required data specified in

The Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, or Transmission Service Provider did not provide any steady-state, dynamics, and short circuit modeling data to its Transmission Planner(s) and Planning Coordinator(s);

OR

The Balancing Authority, Generator

July 9, 2013 Page 14 of 23

Attachment 1;

OR

The Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, or Transmission Service Provider provided steady-state, dynamics, and short circuit modeling data to its Transmission Planner(s) and Planning Coordinator(s), but less than or equal to 25% of the required data failed to meet data format, shareability, level of detail, or case type specifications;

OR

The Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, or Transmission Service

Attachment 1;

OR

The Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, or Transmission Service Provider provided steady-state, dynamics, and short circuit modeling data to its Transmission Planner(s) and Planning Coordinator(s), but greater than 25% but less than or equal to 50% of the required data failed to meet data format, shareability, level of detail, or case type specifications;

OR

The Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, or

Attachment 1;

OR

The Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, or Transmission Service Provider provided steady-state, dynamics, and short circuit modeling data to its Transmission Planner(s) and Planning Coordinator(s), but greater than 50% but less than or equal to 75% of the required data failed to meet data format, shareability, level of detail, or case type specifications;

OR

The Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, or

Owner, Load Serving Entity, Resource Planner, or Transmission Service Provider provided steady-state, dynamics, and short circuit modeling data to its Transmission Planner(s) and Planning Coordinator(s), but failed to provide greater than 75% of the required data specified in Attachment 1;

OR

The Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, or Transmission Service Provider provided steady-state, dynamics, and short circuit modeling data to its Transmission Planner(s) and Planning

July 9, 2013 Page 15 of 23

Provider failed to provide steady-state, dynamics, and short circuit modeling data to its Transmission Planner(s) and Planning Coordinator(s) within the schedule specified by the data requirements and reporting procedures but did provide the data in less than or equal to 15 calendar days after the specified date.

Transmission Service Provider failed to provide steady-state, dynamics, and short circuit modeling data to its Transmission Planner(s) and Planning Coordinator(s) within the schedule specified by the data requirements and reporting procedures but did provide the data in greater than 15 but less than or equal to 30 calendar days after the specified date.

Transmission Service Provider failed to provide steady-state, dynamics, and short circuit modeling data to its Transmission Planner(s) and Planning Coordinator(s) within the schedule specified by the data requirements and reporting procedures but did provide the data in greater than 30 but less than or equal to 45 calendar days after the specified date.

Coordinator(s), but greater than 75% of the required data failed to meet data format, shareability, level of detail, or case type specifications;

OR

The Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, or Transmission Service Provider failed to provide steady-state, dynamics, and short circuit modeling data to its Transmission Planner(s) and Planning Coordinator(s) within the schedule specified by the data requirements and reporting procedures but did provide the data in greater than 45 calendar days after the specified date.

July 9, 2013 Page 16 of 23


Lower The Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, or Transmission Service Provider failed to provide a written response to its Transmission Planner(s) or Planning Coordinator(s) according to the specifications of Requirement R4 within 30 calendar days (or within a longer period agreed upon by the notifying Planning Coordinator or Transmission Planner), but did provide the response within 45 calendar days (or within 15 calendar days after the longer period agreed upon by the notifying Planning Coordinator or Transmission Planner).

The Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, or Transmission Service Provider failed to provide a written response to its Transmission Planner(s) or Planning Coordinator(s) according to the specifications of Requirement R4 within 30 calendar days (or within a longer period agreed upon by the notifying Planning Coordinator or Transmission Planner), but did provide the response within greater than 45 calendar days but less than or equal to 60 calendar days (or within greater than 15 calendar days but less than or equal to 30 calendar days after the

The Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, or Transmission Service Provider failed to provide a written response to its Transmission Planner(s) or Planning Coordinator(s) according to the specifications of Requirement R4 within 30 calendar days (or within a longer period agreed upon by the notifying Planning Coordinator or Transmission Planner), but did provide the response within greater than 60 calendar days but less than or equal to 75 calendar days (or within greater than 30 calendar days but less than or equal to 45 calendar days after the

The Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, or Transmission Service Provider failed to provide a written response to its Transmission Planner(s) or Planning Coordinator(s) according to the specifications of Requirement R4 within 30 calendar days (or within a longer period agreed upon by the notifying Planning Coordinator or Transmission Planner);

OR

The Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, or Transmission Service Provider did provide a written response to its

July 9, 2013 Page 17 of 23

longer period agreed upon by the notifying Planning Coordinator or Transmission Planner).

longer period agreed upon by the notifying Planning Coordinator or Transmission Planner).

Transmission Planner(s) or Planning Coordinator(s) according to the specifications of Requirement R4 but not within greater than 75 calendar days (or within greater than 45 calendar days after the longer period agreed upon by the notifying Planning Coordinator or Transmission Planner).


Medium The Planning Coordinator submitted the required data to the ERO or its designee but failed to provide less than or equal to 25% of the required data in the format specified by the ERO or its designee;

OR

The Planning Coordinator failed to provide the required

The Planning Coordinator submitted the required data to the ERO or its designee but failed to provide greater than 25% or less than or equal to 50% of the required data in the format specified by the ERO or its designee;

OR


The Planning Coordinator submitted the required data to the ERO or its designee but failed to provide greater than 50% or less than or equal to 75% of the required data in the format specified by the ERO or its designee;

OR


The Planning Coordinator submitted the required data to the ERO or its designee but failed to provide greater than 75% of the required data in the format specified by the ERO or its designee;

OR

The Planning Coordinator failed to provide the required data according to the

July 9, 2013 Page 18 of 23

data according to the schedule specified by the ERO or its designee but did provide the data within 15 calendar days after the specified date;

OR

The Planning Coordinator submitted the required data to the ERO or its designee but failed to include documentation and reasons for any data modifications.

provide the required data according to the schedule specified by the ERO or its designee but did provide the data in greater than 15 calendar days but less than or equal to 30 calendar days after the specified date.

provide the required data according to the schedule specified by the ERO or its designee but did provide the data in greater than 30 calendar days but less than or equal to 45 calendar days after the specified date.

schedule specified by the ERO or its designee and did not provide the data within 45 calendar days after the specified date.

D. Regional Variances

None.

E. Interpretations

None.

F. Associated Documents

None.

July 9, 2013 Page 19 of 23

MOD-032-01 – ATTACHMENT 1:

“At a minimum” Data Reporting Requirements

The table, below, indicates the “at a minimum” information that is required to effectively model the interconnected transmission system for the Near-Term Transmission Planning Horizon and Long-Term Transmission Planning Horizon. A Planning Coordinator may specify additional information that includes specific information required for each item in the table below. Each functional entity1 responsible for reporting the respective data in the table is identified by brackets “[functional entity]” adjacent to and following each data item. The data reported shall be as identified by the bus number, name, and/or identifier that is assigned in conjunction with the PC or TP.

steady-state (Items marked with an asterisk indicate data that vary with

system operating state or conditions. Those items may have different data provided for different modeling scenarios)

dynamics

short-circuit

1. Each Bus [TO] a. nominal voltage b. area, zone and owner

2. Aggregate Demand at each bus [LSE] a. real and reactive power* b. in-service status* c. load type (e.g., firm, interruptible, scalable, etc.)

3. Generating Units2 [GO, RP (for future planned resources only)]

a. real power capabilities - gross maximum and minimum values b. reactive power capabilities - maximum and minimum values at real

power capabilities in 3a above c. station service auxiliary load (provide data in the same manner as that

required for aggregate Demand under item 2, above). d. regulated bus* e. voltage set point* (as provided to the GO by the TOP) f. owner(s) information (including percentage of ownership if jointly

owned) g. machine MVA base

1. Generator [GO] a. Synchronous machines,

including, as appropriate to the model: i. inertia constant

ii. damping coefficient iii. saturation parameters iv. direct and quadrature axes

reactances and time constants

b. Other technologies, including, as appropriate to the model: i. inertia constant

ii. damping coefficient iii. saturation parameters iv. direct and quadrature axes

reactances and time constants

1. Positive Sequence Data – provide for all applicable elements in column “steady-state” [GO, TO]

2. Negative Sequence Data – provide for all applicable elements in column “steady-state” [GO, TO]

3. Zero Sequence Data – provide for all applicable elements in column “steady-state” [GO,TO] a. Bus b. Generator c. Transmission line d. Transformer (to include

connection type) 4. Mutual Line Impedance Data [TO]

1 For purposes of this attachment, the functional entity references are represented by abbreviation as follows: Balancing Authority (BA), Generator Owner (GO), Load Serving Entity (LSE), Planning

Coordinator (PC), Resource Planner (RP), Transmission Owner (TO), Transmission Operator (TOP), Transmission Planner (TP), and Transmission Service Provider (TSP).

2 Including synchronous condensers, pumped storage, etc.

July 9, 2013 Page 20 of 23



dynamics

short-circuit

h. share of reactive contribution for voltage regulation* i. generator step up transformer data (provide same data as that required

for transformer under item 6, below) j. generator prime mover and fuel type (hydro, wind, fossil, solar, nuclear,

etc) 4. AC Transmission Line or Circuit (series capacitors and reactors shall be

explicitly modeled as individual line segments) [TO] a. impedance (positive sequence)

i. resistance ii. reactance

iii. susceptance (line charging) b. ratings (normal and emergency)* c. equipment status*

5. DC Transmission systems – identified by DC line name or number [TO] a. AC bus number and name for each converter b. line parameters c. ratings d. rectifier and inverter data

6. Transformer (voltage and phase-shifting) [TO] a. nominal voltages of windings b. impedance(s) c. tap ratios (voltage or phase angle)* d. minimum and maximum tap position limits e. number of tap positions (for both the ULTC and NLTC) f. regulated bus (for voltage regulating transformers)* g. regulated voltage limits or MW band limits* h. ratings (normal and emergency)*

7. Reactive compensation (shunt capacitors and reactors) [TO] a. admittances (MVars) of each capacitor and reactor b. regulated voltage band limits c. mode of operation (fixed, discrete, continuous, etc.) d. regulated bus* e. share of reactive contribution for voltage regulation*

8. Static Var Systems [TO] a. reactive limits b. voltage set point* c. fixed shunt switching, if applicable

2. Excitation System [GO] 3. Governor [GO] 4. Power System Stabilizer [GO] 5. Demand [LSE] (consistent with system

load representation (composite load model) and components as a function of frequency and voltage)

6. Wind Turbine Data [GO] 7. Photovoltaic systems [GO] 8. Static Var Systems and FACTS [GO, TO,

LSE] 9. DC system models

July 9, 2013 Page 21 of 23



dynamics

short-circuit

d. share of reactive contribution for voltage regulation* 9. Other information requested by the Planning Coordinator or Transmission

Planner necessary for modeling purposes. [BA, GO, LSE, TO, TSP]

Application Guidelines

July 9, 2013 Page 22 of 23

Guidelines and Technical Basis

*(Listed below are several concepts, by topic, that may need further detail provided to them in the guidance section of the standard. In this stage of developing proposals, the following ideas are not by any means intended to be an exhaustive list of topics that may need further attention in guidance, and we invite further recommendations of items that may be useful in this section.)

If a Transmission Planner and Planning Coordinator mutually agree, a Transmission Planner may collect and aggregate some or all data from providing entities, and the Transmission Planner may then provide that data directly to the Planning Coordinator(s) on behalf of the providing entities. The submitting entities are responsible for getting the data to both the TP and the PC, but nothing precludes them from arriving at mutual agreements for them to provide it to the TP, who then provides it to the PC. Such agreement does not relieve the submitting entity from responsibility under the standard, nor does it make the consolidating entity liable for the submitting entities’ compliance under the standard (in essence, nothing precludes parties from agreeing to consolidate or act as a conduit to pass the data, and it is in fact encouraged in certain circumstances, but the requirement is aimed at the act of submitting the data). Notably, there is no requirement for the TP to provide data to the PC. The intent, in part, is to address potential concerns from entities that they would otherwise be responsible for the quality, nature, and sufficiency of the data provided by other entities.

An entity submitting data per the requirements of this standard who need to determine the PC for the area, as a starting point, should contact the local TO for information on the TO’s PC. Typically, the PC will be the same for both the local TO and those entities connected to the TO’s system. If this is not the case, the local TO’s PC can typically provide contact information on other PCs in the area. If the entity (e.g., a GO) is requesting interconnection for a new generator, the entity can determine who the PC is for that area at the time a generator interconnection request is submitted. Often the TO and PC are the same entity, or the TO can provide information on contacting the PC. The entity should specify as the reason for the request to the TO that the entity needs to provide data to the PC according to this standard. Nothing in the proposed requirement language of this standard is intended to preclude coordination between entities such that one entity, serving only as a conduit, provides the other entity’s data to the PC. This can be accomplished if it is mutually agreeable by, for example, the GO (or other entity), TP, and the PC. This does not, however, relieve the original from its obligations under the standard to provide data, nor does it pass on the compliance obligation of the entity. The original entity is still accountable for making sure that the data has been provided to the PC according to the requirements of this standard.

The standard language recognizes that differences exist among the three interconnections (Eastern, ERCOT and WECC). Presently, the Eastern and Texas Interconnections on an annual basis build seasonal cases, while the WECC Interconnection builds cases on a continuous basis throughout the year. The intent of the standard is not to change established processes and procedures in each of the Interconnections, but to create a framework to support both what is already in place or what it may transition into in the future, and to provide further guidance in a


July 9, 2013 Page 23 of 23

common platform for the collection of data that is necessary for the building of the Interconnection model(s).

The construct that these standards replace did not specifically list which Functional Entities were required to provide specific data. Attachment 1 specifically identifies the entities responsible for the data required for the building of the Interconnection model(s).

MOD-033-1 — Steady-State and Dynamic System Model Validation







This is the first posting of this standard for a 45-day formal comment period and initial ballot. Several directives remain outstanding (including from FERC Order No. 693) that relate to MOD-010 through MOD-015. This standard and Standard MOD-032-1 seek to address the outstanding directives while simultaneously incorporating recommendations for improvement from the NERC Planning Committee’s System Analysis and Modeling Subcommittee (SAMS).


Post SAR July 2013


Recirculation ballot September 2013




Effective Dates

In those jurisdictions where regulatory approval is required, this standard shall become effective on the first day of the twelfth calendar quarter after applicable regulatory approval or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities. In those jurisdictions where no regulatory approval is required, this standard shall become effective on the first day of the twelfth calendar quarter after Board of Trustees approval.

Version History


1 TBD Developed as a new standard for system validation to address outstanding directives from FERC Order No. 693 and recommendations from several other sources.



Definitions of Terms Used in Standard

None



When this standard has received ballot approval, the text boxes will be moved to the Application Guidelines Section of the Standard.

A. Introduction

1. Title: Steady-State and Dynamic System Model Validation


3. Purpose: To establish consistent validation requirements to facilitate the collection of accurate data and building of models to analyze the reliability of the interconnected transmission system.

4. Applicability:


4.1.1 Planning Coordinators

4.1.2 Reliability Coordinators

4.1.3 Transmission Operators

5. Background:

MOD-033-1 exists in conjunction with MOD-032-1, both of which are related to system-level modeling and validation. Standard MOD-032-1 is a consolidation and replacement of existing MOD-010-0, MOD -011-0, MOD-012-0, MOD-013-1, MOD-014-0, and MOD-015-0.1, and it requires a minimum level of data submission by applicable data owners to their respective Transmission Planners and Planning Coordinators to support the interconnection model building process in their interconnection. Standard MOD-033-1 is a new standard, and it requires each Planning Coordinator to implement a documented process to perform model validation within its planning area.

The transition and focus of responsibility upon the Planning Coordinator function in both standards are driven by several recommendations and FERC directives (to include several remaining directives from FERC Order No. 693), which are discussed in greater detail in the rationale sections of the standards. One of the most recent and significant set of recommendations came from the NERC Planning Committee’s System Analysis and Modeling Subcommittee (SAMS). SAMS proposed several improvements to the modeling data standards, to include consolidation of the standards (that whitepaper is available from the December 2012 NERC Planning Committee’s agenda package, item 3.4, beginning on page 99, here: http://www.nerc.com/comm/PC/Agendas%20Highlights%20and%20Minutes%20DL/2012/2012_Dec_PC%20Agenda.pdf).






Rationale for R1:

In FERC Order No. 693, paragraph 1210, the Commission directed inclusion of “a requirement that the models be validated against actual system responses.” Furthermore, the Commission directs in paragraph 1211, “that actual system events be simulated and if the model output is not within the accuracy required, the model shall be modified to achieve the necessary accuracy.” Paragraph 1220 similarly directs validation against actual system responses relative to dynamics system models. In FERC Order 890, paragraph 290, the Commission states that “the models should be updated and benchmarked to actual events.” Requirement R1 addresses these directives.

Requirement R1 requires the PC to implement a documented process to validate data for steady state and dynamic models within its area, which is consistent with the Commission directives. The validation of the full interconnection model is left up to the ERO or its designees, and is not addressed by this standard. The following items were chosen for the validation requirement:

A. Comparison of power flow model to state estimator snapshot; and

B. Simulation of significant system disturbances and comparing the simulation results with the actual event results.

Implementation of these validations will result in more accurate power flow and dynamic models. This, in turn, should result in better correlation between system flows and voltages seen in power flow studies and the actual values seen by system operators during outage conditions. Similar improvements should be expected for dynamics studies, such that the results will more closely match the actual responses of the power system to disturbances.

Validation of model data is a good utility practice, but it does not easily lend itself to Reliability Standards requirement language. Furthermore, it is challenging to determine specifications for thresholds of disturbances that should be validated and how they are determined. Therefore, this requirement focuses on the Planning Coordinator performing validation pursuant to the criteria listed without specifying the details of “how” it must validate, which is necessarily dependent upon facts and circumstances. Other validations are best left to guidance rather than standard requirements.

Part 1.3 supports confirming or correcting the model for accuracy in coordination with the data owner when the actual system response does not match expected system performance, which could be accomplished through use of MOD-032-1, Requirement R4, if necessary.



R1. Each Planning Coordinator must implement a documented process to validate the data used for steady state and dynamic analyses (the data submitted under MOD-TBD-01 (the single modeling data standard)) for its planning area against actual system responses that includes, at a minimum, the following items: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

1.1. Validate its portion of the system in the power flow model by comparing it to actual system behavior, represented by a state estimator case or other Real-time data sources to check for discrepancies that the Planning Coordinator determines are large or unexplained at least once every 24 calendar months through simulation.

1.2. Validate its portion of the system in the dynamic models at least once every 24 calendar months through simulation of a dynamic local event, unless the time between dynamic local events exceeds 24 calendar months. If the time between dynamic local events exceeds 24 calendar months, validate its portion of the system in the dynamic models through simulation of the next dynamic local event. Complete the simulation within 12 calendar months of the local event.

1.3. Coordinate with the data owner(s) to confirm or correct the model for accuracy when the discrepancy between actual system response and expected system performance is too large, as determined by the Planning Coordinator.

M1. Examples of evidence may include, but are not limited to, a documented validation process and evidence that demonstrates the implementation of the required components of the process.

R2. Each Reliability Coordinator and Transmission Operator shall provide actual system behavior data (or a written response that it does not have the requested data) to any Planning Coordinator that the Planning Coordinator requests to perform validation under Requirement 1 within 30 calendar days of a written request, such as, but not limited to, state estimator case or other Real-time data (including disturbance data recordings) necessary for actual system response validation. [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]

Rationale for R2:

The Planning Coordinator will need actual real time system data in order to perform the validations required in R1. The Reliability Coordinator or Transmission Operator may have this data. Requirement R2 requires the Reliability Coordinator and Transmission Operator to supply actual system data, if it has the data, to any requesting Planning Coordinator for purposes of model validation under Requirement R1.



M2. Each Reliability Coordinator and Transmission Operator shall provide evidence, such as email notices or postal receipts showing recipient and date that it has distributed the requested data or written response that it does not have the data, to any Planning Coordinator who has indicated a need for the data for validation purposes within 30 days of a written request in accordance with Requirement R2; or a statement by the Reliability Coordinator that it has not received notification regarding data necessary for validation by any Planning Coordinator.



C. Compliance

1. Compliance Monitoring Process


Regional Entity


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 CEA may ask an entity to provide other evidence to show that it was compliant for the full time period since the last audit.

The Responsible Entity shall keep data or evidence to show compliance as identified below unless directed by its CEA to retain specific evidence for a longer period of time as part of an investigation:

Each Responsible Entity shall retain evidence of each requirement in this standard for three calendar years.

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

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


Compliance Audits

Self-Certifications

Spot Checking

Compliance Violation Investigations

Self-Reporting

Complaints Text


None






Medium The Planning Coordinator did not validate its portion of the system in the power flow model as required by R1 but did validate in less than or equal to 28 calendar months;

OR

The Planning Coordinator did not complete simulation of the local event within 12 calendar months in validating its portion of the system in the dynamic models as required by R1 but did complete the simulation in less than or equal to 15 calendar months.

The Planning Coordinator documented and implemented a process to validate data but did not address one of the three required topics under Requirement R1;

OR

The Planning Coordinator did not validate its portion of the system in the power flow model as required by R1 but did validate in greater than 28 calendar months but less than or equal to 32 calendar months;

OR

The Planning

The Planning Coordinator documented and implemented a process to validate data but did not address two of the three required topics under Requirement R1;

OR

The Planning Coordinator did not validate its portion of the system in the power flow model as required by R1 but did validate in greater than 32 calendar months but less than or equal to 36 calendar months;

OR

The Planning

The Planning Coordinator did not have a validation process at all or did not document or implement any of the three required topics under Requirement R1;

OR

The Planning Coordinator did not validate its portion of the system in the power flow model as required by R1 or did validate but exceeded 36 calendar months between validation;

OR

The Planning Coordinator did not complete simulation of the local event at all in

July 9, 2013 Page 10 of 13

Coordinator did not complete simulation of the local event within 12 calendar months in validating its portion of the system in the dynamic models as required by R1 but did complete the simulation in greater than 15 calendar months but less than or equal to 18 calendar months.

Coordinator did not complete simulation of the local event within 12 calendar months in validating its portion of the system in the dynamic models as required by R1 but did complete the simulation in greater than 18 calendar months but less than or equal to 21 calendar months.

validating its portion of the system in the dynamic models as required by R1 or did complete the simulation but exceeded 18 calendar months.


Lower The Reliability Coordinator or Transmission Operator did not provide requested actual system behavior data (or a written response that it does not have the requested data) to a requesting planning coordinator within 30 calendar days of the written request, but did provide the data (or written response that it does not have the requested data) in

The Reliability Coordinator or Transmission Operator did not provide requested actual system behavior data (or a written response that it does not have the requested data) to a requesting planning coordinator within 30 calendar days of the written request, but did provide the data (or written response that it does not have the requested data) in

The Reliability Coordinator or Transmission Operator did not provide requested actual system behavior data (or a written response that it does not have the requested data) to a requesting planning coordinator within 30 calendar days of the written request, but did provide the data (or written response that it does not have the requested data) in

The Reliability Coordinator or Transmission Operator did not provide any requested actual system behavior data (or a written response that it does not have the requested data) to a requesting planning coordinator;

OR

The Reliability Coordinator or Transmission Operator did not provide

July 9, 2013 Page 11 of 13

less than or equal to 45 calendar days.

greater than 45 calednar days but less than or equal to 60 calendar days.

greater than 60 calednar days but less than or equal to 75 calendar days.

requested actual system behavior data (or a written response that it does not have the requested data) to a requesting planning coordinator within 30 calendar days of the written request, but did provide the data (or written response that it does not have the requested data) in greater than 45 calednar days but less than or equal to 60 calendar days.

D. Regional Variances

None.

E. Interpretations

None.

F. Associated Documents

None.


July 9, 2013 Page 12 of 13


*(Listed below are several concepts, by topic, that may need further detail provided to them in the guidance section of the standard. In this stage of developing proposals, the following ideas are not by any means intended to be an exhaustive list of topics that may need further attention in guidance, and we invite further recommendations of items that may be useful in this section.)

Requirement R1:

The requirement focuses on the results-based outcome of developing a process for and performing a validation, but does not prescribe a specific method or procedure for the validation outside of the criteria specified in the requirement. For further information on suggested validation procedures, see “Procedures for Validation of Powerflow and Dynamics Cases” produced by the NERC Model Working Group.

The specific process is left to the judgment of the Planning Coordinator, but the Planning Coordinator is encouraged to develop and include in its process criteria for evaluating discrepancies between actual system behavior or response and expected system performance for determining whether the discrepancies are too large or unexplained.

For the validation in part 1.1 the state estimator case should be taken as close to system peak as possible. However, other snapshots of the system could be utilized if deemed to be more appropriate by the Planning Coordinator. While the requirement specifies “once every 24 calendar months,” entities are encouraged to perform the comparison on a more frequent basis.

In performing the comparison required in part 1.1, the PC should consider, among other criteria:

1. System load;

2. Transmission topology and parameters;

3. Voltage at major buses; and

4. Flows on major transmission elements.

The validation in part 1.1 would include consideration of the load distribution and load power factors (as applicable) used in the power flow models. The validation may be made using metered load data if state estimator cases are not available. The comparison of system load distribution and load power factors shall be made on an aggregate company or power flow zone level at a minimum but may also be made on a bus by bus, load pocket (e.g., within a Balancing Authority), or smaller area basis as deemed appropriate by the Planning Coordinator.

The scope of dynamics model validation is intended to be limited, for purposes of part 1.2, to the Planning Coordinator’s planning area, and the intended emphasis under the requirement is on local events or local phenomena, not the whole interconnection.


July 9, 2013 Page 13 of 13

The validation required in part 1.2 should include simulations which are to be compared with actual system data and may include comparisons of:

Voltages oscillations at major buses

System frequency (for events with frequency excursions)

Real and reactive power oscillations on generating units and major inter-area ties

Part 1.3 could be accomplished in direct coordination with the data owner, and, if necessary, through the provisions of MOD-032-1, Requirement R4 (i.e., the validation performed under this requirement could identify technical concerns with the data). In other words, while this standard is focused on validation, results of the validation may identify data provided under the modeling data standard that needs to be corrected.

While the validation is focused on the PC’s planning area, the model to be used for the validation should be one that contains a wider area of the interconnection than the PC’s area. If the simulations can be made to match the actual system responses by reasonable changes to the data, then the PC should make those changes in coordination with the data provider. However, for some disturbances, the data in the PC’s area may not be what is causing the simulations to not match actual responses. These situations should be reported to the ERO. If a model with estimated data or a generic model is used for a generator and the model response does not match the actual response, then the estimated data should be corrected or a more detailed model should be requested from the data provider.

Compliance Operations Draft Reliability Standard Compliance Guidance for MOD-032-1 and MOD-033-1 July 10, 2013 Introduction The NERC Compliance department (Compliance) worked with the MOD B informal ad hoc group (MOD B Group) in a review of pro forma standards MOD-032-1 and MOD-033-1. The purpose of the review is to discuss the requirements of the pro forma standards to obtain an understanding of their intended purposes and necessary evidence to support compliance. The purpose of this document is to address specific questions posed by the MOD B Group and Compliance in order to aid the drafting of the requirements and provide a level of understanding regarding evidentiary support necessary to demonstrate compliance. While all testing requires levels of auditor judgment, participating in these reviews allows Compliance to develop training and approaches to support a high level of consistency in audits conducted by the Regional Entities. However, this document makes no assessment as to the enforceability of the standard. The following questions should both assist the MOD B Group in further refining the standard and serve as a tool to develop auditor training. MOD-032-1 Questions Question 1 Per MOD-032-1 Requirement R3, will the auditor verify only that the data was delivered as specified, or will the auditor make a determination regarding whether the quality of the data is sufficient? Compliance Response to Question 1 Based on the language in the requirement and the purpose of the standard, which is to facilitate the transfer of data for modeling purposes, the auditor will verify that the data was delivered as specified. This standard does not specify the criteria around quality, so auditors will not make any assessments in that regard. Question 2 Per MOD-033-1 Requirement R1, is it clear what is meant by “unexplained” or “too large?” Compliance Response to Question 2 Based on the language in the requirement and the purpose of the standard, which is to implement a process to validate data, the auditor will verify that the documented process includes a criteria discussion about how the entity will make a determination of “unexplained” or “too large.” Auditors will not assess the quality of the entity’s determination, just that the validation process has been implemented and followed.

Draft Reliability Standard Compliance Guidance for MOD-032-1 and MOD-033-1 July 10, 2013 2

Conclusion In general, Compliance finds the pro forma standard provides a reasonable level of guidance for Compliance Auditors to conduct audits in a consistant manner. The standard establishes timelines, data requirements, and ownership of specific actions. Further, the standard provides reasonable guidance to develop training for Compliance Auditors to execute their reviews. However, Compliance does recommend the MOD B Group address the items noted in the response to the question, if applicable.

Following final approval of the Reliability Standard, Compliance will develop the final Reliability Standards Auditor Worksheet (RSAW) and associated training. Attachment A represents the versions of the pro forma standards requirements referenced in this document.

Attachment A MOD-032-1 Requirements and Measures

R1. Each Planning Coordinator, in conjunction with each of its Transmission Planners, shall develop steady-state, dynamics, and short circuit modeling data requirements and reporting procedures for its planning area, including: [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]

1.1. Specification of the required data that includes, at a minimum, the data listed in Attachment 1;

1.2. Specification of the data format;

1.3. Specification that the data must be shareable on an interconnection-basis to support use in the interconnection models;

1.4. Specification of the level of detail to which equipment shall be modeled;

1.5. Specification of the case types or scenarios to be modeled; and

1.6. A schedule for submission or confirmation of data at least once every 13 calendar months.

M1. Examples of evidence include, but are not limited to, dated documentation or records that the required modeling data requirements and reporting procedures meet the specifications in Requirement R1.

R2. Each Planning Coordinator shall provide its data requirements and reporting procedures developed under Requirement R1 to any Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, Transmission Owner, or Transmission Service Provider in its planning area within 30 calendar days of a written request. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

M2. Each Planning Coordinator shall provide evidence, such as email notices or postal receipts showing recipient and date, that it has distributed the requested data requirements and reporting procedures within 30 days of a written request in accordance with Requirement R2; or a statement by the Planning Coordinator that it has not received a request for its data requirements and reporting procedures.

R3. Each Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, Transmission Owner, and Transmission Service Provider shall provide steady-state, dynamics, and short circuit modeling data to its Transmission Planner(s) and Planning Coordinator(s) according to the data requirements and reporting procedures developed by its Planning Coordinator in Requirement R1. For data that has not changed since the last submission, a


written confirmation that the data has not changed is sufficient. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

M3. Examples of evidence include, but are not limited to, dated documentation or records of submission by a registered entity of the required data to its Transmission Planner(s) and Planning Coordinator(s); or written confirmation that the data has not changed.

R4. Upon delivery of written notification from its Planning Coordinator or Transmission Planner regarding technical concerns with the data submitted under Requirement R3, including the technical basis or reason for the technical concerns, each notified Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, Transmission Owner, or Transmission Service Provider shall respond to the notifying Planning Coordinator or Transmission Planner as follows: [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]

4.1. Provide either updated data or an explanation with a technical basis for maintaining the current data;

4.2. If requested by the notifying Planning Coordinator or Transmission Planner, provide additional dynamics data describing the characteristics of the model, including block diagrams, values and names for all model parameters, and a list of all state variables; and

4.3. Provide the response within 30 calendar days, unless a longer time period is agreed upon by the notifying Planning Coordinator or Transmission Planner.

M4. Examples of evidence include, but are not limited to: dated records of a written request from the Transmission Planner or Planning Coordinator notifying a Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, Transmission Owner, or Transmission Service Provider regarding technical concerns, and additional evidence demonstrating the response to the request meets the specifications of Requirement R4; or a statement by the Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner, Transmission Owner, or Transmission Service Provider that it has not received notification regarding usability or technical concerns.

R5. Each Planning Coordinator must submit the data provided under Requirement R3 to the ERO or its designee to support creation of the interconnection model(s) that includes the Planning Coordinator’s planning area as follows: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

5.1. In the format and according to the schedule specified by the ERO or its designee; and

5.2. Include documentation and reasons for data modifications, if any.


M5. Examples of evidence may include, but are not limited to, dated documentation or records indicating data submission from the Planning Coordinator to the ERO or its designee according to Requirement R5.

MOD-033-1 Requirements and Measures

R1. Each Planning Coordinator must implement a documented process to validate the data used for

steady state and dynamic analyses (the data submitted under MOD-TBD-01 (the single modeling data standard)) for its planning area against actual system responses that includes, at a minimum, the following items: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

1.1. Validate its portion of the system in the power flow model by comparing it to actual system behavior, represented by a state estimator case or other Real-time data sources to check for discrepancies that the Planning Coordinator determines are large or unexplained at least once every 24 calendar months through simulation.

1.2. Validate its portion of the system in the dynamic models at least once every 24 calendar months through simulation of a dynamic local event, unless the time between dynamic local events exceeds 24 calendar months. If the time between dynamic local events exceeds 24 calendar months, validate its portion of the system in the dynamic models through simulation of the next dynamic local event. Complete the simulation within 12 calendar months of the local event.

1.3. Coordinate with the data owner(s) to confirm or correct the model for accuracy when the discrepancy between actual system response and expected system performance is too large, as determined by the Planning Coordinator.

M1. Examples of evidence may include, but are not limited to, a documented validation process and evidence that demonstrates the implementation of the required components of the process.

M2. Each Reliability Coordinator and Transmission Operator shall provide actual system behavior data (or a written response that it does not have the requested data) to any Planning Coordinator that the Planning Coordinator requests to perform validation under Requirement 1 within 30 calendar days of a written request, such as, but not limited to, state estimator case or other Real-time data (including disturbance data recordings) necessary for actual system response validation. [Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]

R2. Each Reliability Coordinator and Transmission Operator shall provide evidence, such as email notices or postal receipts showing recipient and date that it has distributed the requested data or written response that it does not have the data, to any Planning Coordinator who has indicated a need for the data for validation purposes within 30 days of a written request in


accordance with Requirement R2; or a statement by the Reliability Coordinator that it has not received notification regarding data necessary for validation by any Planning Coordinator.

Implementation Plan for Project 2010-03 (MOD-032-1 and MOD-033-1) July 9, 2013 Approvals Requested MOD-032 -1 – Data for Power System Modeling and Analysis MOD-033-1 – Steady-State and Dynamic System Model Validation Prerequisite Approvals None Effective Date New or Revised Standards MOD-032-1 – In those jurisdictions where regulatory approval is required, Requirements R1 and R2 shall become effective on the first day of the fourth calendar quarter after applicable regulatory approval or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities, and Requirements R3, R4, and R5 shall become effective on the first day of the eighth calendar quarter after applicable regulatory approval or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities. In those jurisdictions where no regulatory approval is required, this standard shall become effective on the first day of the fourth calendar quarter after Board of Trustees approval, and Requirements R3, R4, and R5 shall become effective on the first day of the eighth calendar quarter after Board of Trustees approval. MOD-033-1 – In those jurisdictions where regulatory approval is required, this standard shall become effective on the first day of the twelfth calendar quarter after applicable regulatory approval or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities. In those jurisdictions where no regulatory approval is required, this standard shall become effective on the first day of the twelfth calendar quarter after Board of Trustees approval. Standards for Retirement

MOD-010-0, MOD -011-0, MOD-012-0, MOD-013-1, MOD-014-0, and MOD-015-0.1 – Midnight of the day immediately prior to the Effective Date of MOD-032-1, Requirements R1 and R2, in the particular Jurisdiction in which the new standard is becoming effective.

Initial Performance of Periodic Requirements MOD-033-1, Requirement R1, parts 1.1 and 1.2 include periodic components for validation that contain time parameters for subsequent and recurring iterations of implementing the requirement, specified as, “. . . at least once every 24 calendar months . . .”, and responsible entities shall comply initially with those periodic components within 24 calendar months after the Effective Date of MOD-033-1.

MOD B Working Draft (July 9, 2013) of Mapping Document Showing Translation of MOD-010-0, MOD -011-0, MOD-012-0, MOD-013-1, MOD-014-0, and MOD-015-0.1 to MOD-032-1 and MOD-033-1.

Standard: MOD-010-0 – Steady-State Data for Modeling and Simulation of the Interconnected Transmission System Requirement in Approved Standard Translation to

New Standard or Other Action

Description and Change Justification

MOD-010-0 R1 MOD-032-1, R3 Changed to require submission of the data to Planning Coordinators and Transmission Planners


Standard: MOD-011-0 – Maintenance and Distribution of Steady-State Data Requirements and Reporting Procedures

Requirement in Approved Standard Translation to New Standard or

Other Action


MOD-011-0 R1 MOD-032-1, R1 Changed to require Planning Coordinators, in conjunction with each of its Transmission Planners, to develop the data requirements and reporting procedures for their planning areas instead of requiring RROs to develop such requirements and procedures for their respective interconnections. Rather than specify the required components in the requirement parts, MOD-032-1 leverages an attachment to detail each of the steady-state, dynamics, and short circuit “at a minimum” requirements.

MOD B

2

Standard: MOD-011-0 – Maintenance and Distribution of Steady-State Data Requirements and Reporting Procedures Requirement in Approved Standard Translation to



MOD-011-0 R2 MOD-032-1, R1 and R2

Changed to require Planning Coordinators, in conjunction with each of its Transmission Planners, to develop the data requirements and reporting procedures for their planning areas instead of requiring RROs to develop such requirements and procedures for their respective interconnections. Rather than specify the required components in the requirement parts, MOD-032-1 leverages an attachment to detail each of the steady-state, dynamics, and short circuit “at a minimum” requirements. MOD-032-1, Requirement R2 maps to the portion of MOD-011-0, Requirement R2 to “make the data requirements and reporting procedures available on request.”

Standard: MOD-012-0 – Dynamics Data for Modeling and Simulation of the Interconnected Transmission System

Requirement in Approved Standard Translation to New Standard or

Other Action




MOD B

3

Standard: MOD-013-1 – Maintenance and Distribution of Dynamics Data Requirements and Reporting Procedures Requirement in Approved Standard Translation to



MOD-013-1 R1 MOD-032-1, R1 Changed to require Planning Coordinators, in conjunction with each of its Transmission Planners, to develop the data requirements and reporting procedures for their planning areas instead of requiring RROs to develop such requirements and procedures for their respective interconnections. Rather than specify the required components in the requirement parts, MOD-032-1 leverages an attachment to detail each of the steady-state, dynamics, and short circuit “at a minimum” requirements.

MOD-013-1 R2 MOD-032-1, R1 Changed to require Planning Coordinators, in conjunction with each of its Transmission Planners, to develop the data requirements and reporting procedures for their planning areas instead of requiring RROs to develop such requirements and procedures for their respective interconnections. Rather than specify the required components in the requirement parts, MOD-032-1 leverages an attachment to detail each of the steady-state, dynamics, and short circuit “at a minimum” requirements. MOD-032-1, Requirement R2 maps to the portion of MOD-013-1, Requirement R2 to “make the data requirements and reporting procedures available on request.”

MOD B

4

Standard: MOD-014-0 – Development of Steady-State System Models Requirement in Approved Standard Translation to



MOD-014-0 R1 Deleted The modeling data standard focuses on clarifying data submission requirements to support building the interconnection models and creates a framework in MOD-032-1, R4 to support submission of the data by Planning Coordinators for use in building their respective interconnections. The RRO functionality is not in the NERC functional model, and, as such, requiring them to coordinate to build an interconnection model is no longer necessary.

MOD-014-0 R2 Deleted The modeling data standard focuses on clarifying data submission requirements to support building the interconnection models and creates a framework in MOD-032-1, R4 to support submission of the data by Planning Coordinators for use in building their respective interconnections. The RRO functionality is not in the NERC functional model, and, as such, requiring them to coordinate to build an interconnection model is no longer necessary.

MOD B

5

Standard: MOD-015-0.1 – Development of Dynamics System Models Requirement in Approved Standard Translation to



MOD-015-0.1 R1 Deleted The modeling data standard focuses on clarifying data submission requirements to support building the interconnection models and creates a framework in MOD-032-1, R4 to support submission of the data by Planning Coordinators for use in building their respective interconnections. The RRO functionality is not in the NERC functional model, and, as such, requiring them to coordinate to build an interconnection model is no longer necessary.

MOD-015-0.1 R2 Deleted The modeling data standard focuses on clarifying data submission requirements to support building the interconnection models and creates a framework in MOD-032-1, R4 to support submission of the data by Planning Coordinators for use in building their respective interconnections. The RRO functionality is not in the NERC functional model, and, as such, requiring them to coordinate to build an interconnection model is no longer necessary.

MOD B

6

New Requirements not found in existing MOD standards Requirement in Approved Standard Translation to



NEW MOD-032-1, R4 This requirement provides a feedback loop to support clarifying or correcting data that a Planning Coordinator or Transmission Planner identifies as having possible technical concerns. Furthermore, part 3.2, which provides a mechanism to obtain more accurate information and data in cases where the initial data provided has technical or accuracy concerns, meets the directive under FERC Order 693, paragraph 1197, as clarified by FERC Order 693-A, paragraph 131, which stated “that ‘[a]chieving the most accurate possible picture of the dynamic behavior of the Interconnection requires the use of actual data,’” but acknowledges “that, in certain circumstances, actual data may not be initially available and only obtained through ‘verification of the dynamic models with actual disturbance data.’” In those cases, additional detail regarding the data may be necessary.

NEW MOD-032-1, R5 This is a new requirement that supports creation of a framework for submission of the data by Planning Coordinators for use in building their respective interconnection-wide models.

NEW MOD-033-1, R1 This is a new standard that addresses validation, and it also meets several directives from FERC Order Nos. 890 and 693 regarding the validation of models to ensure that expected system behavior acceptably matches actual system response.

MOD B

7

New Requirements not found in existing MOD standards Requirement in Approved Standard Translation to



NEW MOD-033-1, R1 The Planning Coordinator will need actual real time system data in order to perform the validations required in R1. The Reliability Coordinator may have this data. R2 requires the Reliability Coordinator to supply real time data, if it has the data, to any requesting Planning Coordinator.

NERC | MOD B Informal Development History | July 18, 2013 1 of 14

Informal Development Background of the MOD B Standards

July 18, 2013



NERC | MOD B Informal Development History| July 18, 2013 2 of 14

Table of Contents Table of Contents ......................................................................................................................................................................... 2 Executive Summary ..................................................................................................................................................................... 3 History of the MOD B Informal Development ............................................................................................................................. 6

Ad Hoc Group Meetings ........................................................................................................................................................... 6

Other Outreach ........................................................................................................................................................................ 6

Outstanding Directives from FERC Order 890 ............................................................................................................................. 7 Para 290 ................................................................................................................................................................................... 7

Consideration of Issue or Directive ...................................................................................................................................... 7

Outstanding Directives from FERC Order 693 ............................................................................................................................. 8 Para 1148 ................................................................................................................................................................................. 8


Para 1154 ................................................................................................................................................................................. 8


Para 1155 ................................................................................................................................................................................. 8


Para 1662 ................................................................................................................................................................................. 9


Para 1178 ................................................................................................................................................................................. 9


Para 1183 ................................................................................................................................................................................. 9


Para 1184 ................................................................................................................................................................................. 9


Para 1197 ............................................................................................................................................................................... 10

Consideration of Issue or Directive .................................................................................................................................... 10

Para 1199 ............................................................................................................................................................................... 10


Para 1210 ............................................................................................................................................................................... 10


Para 1211 ............................................................................................................................................................................... 10


Para 1220 ............................................................................................................................................................................... 11


Conclusion ................................................................................................................................................................................. 12 Appendix A: Entity Participants ................................................................................................................................................. 13


Executive Summary This document provides a summary and information regarding the informal development efforts of the MOD B ad hoc group. A separate, thorough white paper and recommendations regarding MOD-010 through MOD-015 was completed by the NERC Planning Committee’s System Analysis and Modeling Subcommittee (SAMS) (that whitepaper is available from the December 2012 NERC Planning Committee’s agenda package, item 3.4, beginning on page 99, here: http://www.nerc.com/comm/PC/Agendas%20Highlights%20and%20Minutes%20DL/2012/2012_Dec_PC%20Agenda.pdf). Additionally, that whitepaper provided significant input into the technical background and discussion included within the Standards Authorization Request (SAR), and, for those reasons, a more thorough technical discussion of MOD-010 through MOD-015 is not repeated in this document. NERC Reliability Standards MOD-010-0, MOD -011-0, MOD-012-0, MOD-013-1, MOD-014-0, and MOD-015-0.1 (referred to herein as the “existing MOD B standards”) address modeling data requirements that support the mathematical model representations of transmission, generation, and load that are the foundation of virtually all power system studies. Of the six existing MOD B standards, only two were approved by the Federal Energy Regulatory Commission (“FERC” or “Commission”) in Order No. 693. Four of them were neither approved nor remanded, and they remain in a pending status. The following provides a brief summary and status of the existing MOD B standards:

• The existing MOD B Standards o MOD-010-0—Steady-State Data for Modeling and Simulation of the Interconnected Transmission System o MOD-011-0—Maintenance and Distribution of Steady-State Data Requirements and Reporting Procedures o MOD-012-0—Dynamics Data for Modeling and Simulation of the Interconnected Transmission System o MOD-013-1—Maintenance and Distribution of Dynamics Data Requirements and Reporting Procedures o MOD-014-0—Development of Steady-State Models o MOD-015-0.1—Development of Dynamics System Models

• Four existing MOD B standards are not approved o MOD-011, MOD-013, MOD-014 and MOD-015 were not approved by FERC Order No. 693 and remain in

“pending” state due to their “fill-in-the-blank” nature, with requirements applicable to Regional Reliability Organizations (RROs).

o Approved standards MOD-010 and MOD-012 refer to specific modeling needs and processes outlined in unapproved standards MOD-011 and MOD-013, respectively.

• FERC directives regarding the existing MOD B standards remain unaddressed (discussed in detail later in this document)

o FERC Order No. 890 (issued February 2007): 1 directive unaddressed o FERC Order No. 693 (issued March 2007): 12 directives unaddressed

NERC initiated an informal development process to address the remaining directives related to the existing MOD B standards from FERC Order Nos. 890 and 693. Participants were industry subject matter experts, NERC staff, and staff from FERC’s Office of Electric Regulation. In discussing the existing MOD B standards during industry outreach, the informal effort proposed creation of two new reliability standards to replace the existing MOD B standards. The proposal included in this SAR package includes a combined modeling data standard, MOD-032-1, and a new validation standard to address directives related to validation, MOD-033-1 (collectively referred to herein as “proposed MOD B standards”). The proposed MOD B standards are as follows:

• MOD-032-1—Data for Power System Modeling and Analysis • MOD-033-1—Steady-State and Dynamic System Model Validation

In preparing proposals to address the outstanding directives and proposed improvements to MOD-010 through MOD-015, the ad hoc group ensured that the requirements in the proposals were results-based and considered criteria from the Paragraph 81 project (Project 2013-02 Paragraph 81). The group considered the criteria from the Paragraph 81 project to ensure that the standards proposals did not create requirements that meet those criteria. The Paragraph 81 project also prepared a “Paragraph 81 Project Technical White Paper,” dated December 20, 2012, that includes discussion of the identifying criteria that must be satisfied before a

http://www.nerc.com/comm/PC/Agendas%20Highlights%20and%20Minutes%20DL/2012/2012_Dec_PC%20Agenda.pdf�

Executive Summary


Reliability Standard requirement may be proposed for retirement.1 Specifically, for a Reliability Standard requirement to be proposed for retirement, it must satisfy both the overarching criterion that it requires an activity or task that does little, if anything, to benefit reliability and additional identifying criteria (such as criteria that it is administrative, reporting, redundant, etc., as discussed in the Paragraph 81 Technical White Paper).2

In comments submitted to the Paragraph 81 project, there were some comments proposing retirement of requirements in existing MOD-010 and MOD-012 related to reporting data to the RROs on the basis that they were administrative or reporting requirements, or that the information could be collected via vehicles other than a Reliability Standard. In creating the proposed MOD B standards, the ad hoc group carefully considered these suggestions. The proposed MOD B requirements specify who must provide specific types of data to whom for purposes of supporting the system-wide Interconnection models. Importantly, with respect to modeling, providing modeling data itself supports reliability objectives. The paragraph 81 identifying criterion for administrative requirements (criterion B1) applies when the requirement “requires responsible entities to perform a function that is administrative in nature, does not support reliability and is needlessly burdensome.”3 Similarly, the identifying criterion for reporting requirements (criterion B4) applies to requirements that obligate responsible entities to report to a Regional Entity, NERC, or another party or entity “on activities which have no discernible impact on promoting the reliable operation of the BES and if the entity failed to meet this requirement there would be little reliability impact.”4

Absence of modeling data for use in the Interconnection models would be expected to have a reliability impact, and the requirements in the proposed MOD B standards do not create requirements that meet the Paragraph 81 criteria because they establish consistent modeling data requirements and reporting procedures to support analysis of the reliability of the interconnected transmission system.

The proposed MOD B standards are related to system-level modeling and validation. Standard MOD-032-1 is a consolidation and replacement of existing MOD-010-0, MOD -011-0, MOD-012-0, MOD-013-1, MOD-014-0, and MOD-015-0.1, and it requires a minimum level of data submission by applicable data owners to their respective Transmission Planners and Planning Coordinators to support the interconnection model building process in their interconnection. Standard MOD-033-1 is a new standard, and it requires each Planning Coordinator to implement a documented process to perform model validation within its planning area. The modeling data standard proposal, MOD-032-1, is intended to provide clear expectations of “who” provides “what” data to “whom.” It does not prescribe the model building itself, as there are other requirements, namely from TPL-001-4, that address certain Planning Coordinator (PC) and Transmission Planner (TP) obligations in model building. Instead, the standard focuses on modeling data in support of, ultimately, the building of each interconnection model. The requirements specify the “at a minimum” data that must be provided by each data owner. MOD-032-1 also recognizes the differences among interconnections in model building processes, but creates an obligation for PCs to provide the collected data in a manner that accounts for those differences. It specifies that PCs must submit the modeling data to the “ERO or its designee” to support the interconnection model building process in the submitting PC’s particular planning area. While different entities in each of the three interconnections create the interconnection model, the requirement to submit the data to the “ERO or its designee” supports a framework whereby NERC, in collaboration with other organizations, can designate the appropriate organizations in each interconnection to build the interconnection-specific model. It does not prescribe a specific group or process to build the larger Interconnection models, but only requires the PCs to submit data in support of the models’ creation, consistent with the SAMS Proposed Improvements to NERC MOD Standards referenced earlier (at page 3 of that whitepaper) that, “industry best practices and existing processes should be considered in the development of requirements, as many entities are successfully coordinating their efforts.” (emphasis added).

1 Paragraph 81 Project Technical White Paper, December 20, 2012. Available at http://www.nerc.com/pa/Stand/Project%20201302%20Paragraph%2081%20RF/P81_Phase_I_technical_white_paper_FINAL.pdf. 2 See Id. at p. 7 and 8. 3 Id. at p. 8. (Emphasis added). 4 Id. at p. 9. (Emphasis added).

http://www.nerc.com/pa/Stand/Project%20201302%20Paragraph%2081%20RF/P81_Phase_I_technical_white_paper_FINAL.pdf�

http://www.nerc.com/pa/Stand/Project%20201302%20Paragraph%2081%20RF/P81_Phase_I_technical_white_paper_FINAL.pdf�

Executive Summary


For example, under current practice, the Eastern Interconnection Reliability Assessment Group (ERAG) builds the Eastern Interconnection models, the Western Electricity Coordinating Council (WECC) builds the Western Interconnection models, and the Electric Reliability Council of Texas (ERCOT) builds the Texas Interconnection models. This standard does not require a change to that construct, and, assuming continued agreement by those organizations, ERAG, WECC, and ERCOT could be the “designee” for each interconnection. Similarly, the requirement does not prohibit transition, and the standard would not likely need to be updated if the interconnection model building process changed in the future. MOD-033-1 is a new standard focused on PC-level system validation within each PC planning areas. At its core, the standard establishes a requirement for each PC to implement a documented process to validate data for steady state and dynamic models within its area, which is consistent with the Commission directives. The validation of the full interconnection model is left up to the ERO or its designees, and is not addressed by this standard. Validation of model data is a good utility practice, but it does not easily lend itself to Reliability Standards requirement language. Furthermore, it is challenging to determine specifications for thresholds of disturbances that should be validated and how they are determined. Therefore, this standard focuses on the Planning Coordinator performing validation pursuant to the required criteria without specifying the details of “how” it must validate, which is necessarily dependent upon facts and circumstances.


History of the MOD B Informal Development Ad Hoc Group Meetings The MOD B informal development group—a small group of industry subject matter experts, NERC standards staff, NERC reliability initiatives and systems analysis staff, and participants from FERC staff—met face to face several times to discuss the proposals and the outstanding directives from FERC Order Nos. 890 and 693 as follows:

• February 12-14, 2013 at NERC’s Washington, D.C. office.

• March 13-14, 2013 in Atlanta, GA.

• April 9-10, 2013, in Washington, D.C.

• April 17-18 in Baltimore, MD.

• June 12-13 at NERC’s Atlanta, GA office.

Other Outreach There were three technical workshops in support of the MOD B informal development efforts. The purpose of these one-day workshops was to encourage industry participation and to gain industry insight into the topics addressed by the proposed MOD B standards. The three workshops were strategically placed within the western, central, and eastern locations of North America. The first one-day workshop occurred on May 9, 2013, in Minneapolis, Minnesota. There were 50 in-person attendees and 277 online registrants. The second one-day workshop occurred on June 18, 2013, in Salt Lake City, Utah. There were almost 40 in-person attendees and 186 online registrants. The third one-day workshop occurred on June 25, 2013 in Baltimore, Maryland. There were approximately 20 in-person attendees and 199 online registrants. Topics of the workshops included:

• Informal development background

• The current practices and associated recommendations for the MOD-010 through MOD-015 standards;

• Approaches for each of the Modeling Data and Validation standard proposals and the responsibilities in these proposals as applied to various functional entities;

• Roles of the Planning Coordinator and Transmission Planner in the new standards;

• Interconnection model building impacts; and

• Participant-focused question and answer sessions. The MOD B ad hoc group also conducted an industry webinar on April 12, 2013 which had 412 online registrants.


Outstanding Directives from FERC Order 890 Para 290 The Commission directs public utilities, working through NERC, to modify the reliability standards MOD-010 through MOD-025 to incorporate a requirement for the periodic review and modification of models for (1) load flow base cases with contingency, subsystem, and monitoring files, (2) short circuit data, and (3) transient and dynamic stability simulation data, in order to ensure that they are up to date. This means that the models should be updated and benchmarked to actual events. We find that this requirement is essential in order to have an accurate simulation of the performance of the grid and from which to comparably calculate ATC, therefore increasing transparency and decreasing the potential for undue discrimination by transmission providers. Consideration of Issue or Directive The concept that models should be updated and benchmarked, through periodic review and modification, are fully covered by both new standards addressing modeling data MOD-032-1 and model validation MOD-033-1. MOD-032-1 thoroughly addresses modeling data submission and review, along with providing a mechanism to update data that may have technical issues. MOD-033-1 addresses validation of models to ensure that expected system behavior acceptably matches actual system response. Additionally, MOD-032-1, Requirement R1 covers item (2) short circuit data and item (3) transient and dynamic stability simulation data by requiring those items as part of the data requirements, and MOD-032-1, Requirement R4 provides a feedback loop for issues of data from the data owners. The portion of the directive related to contingency, subsystem, and monitoring files were addressed by MOD-001-1a, Requirement R9, and further consideration, if any, is being addressed by the MOD A effort.


Outstanding Directives from FERC Order 693 Para 1148 Supported by many commenters, we adopt the NOPR proposal to direct the ERO to modify MOD-010-0 to require filing of all of the contingencies that are used in performing steady-state system operation and planning studies. We believe that access to such information will enable planners to accurately study the effects of contingencies occurring in neighboring systems on their own systems, which will benefit reliability. Because of the lack of information on contingency outages and the automatic actions that result from these contingencies, planners have not been able to analyze neighboring conditions accurately, thereby potentially jeopardizing reliability on their own and surrounding systems. This requirement will make transmission planning data more transparent, consistent with Order No. 890 requiring greater openness of the transmission planning process. Consideration of Issue or Directive For operations, the sharing of contingencies is covered by MOD-001-1a, and for planning, TPL-001-4 requires lists of Contingencies be compiled in Requirements R3 and R4 as part of the required planning assessments in that standard. Those planning assessments must be distributed to adjacent PCs and TPs, and to any other functional entity with a reliability need, addressing the directives’ focus related to access to information by planners in paragraphs 1148, 1154, 1178, and 1183.

Para 1154 We agree with APPA, SoCal Edison and TVA that the functional entity responsible for providing the list of contingencies in performing planning studies should be the transmission planner, instead of the transmission owner, as proposed in the NOPR. We also agree with APPA that the transmission operator should be one of the entities required to list contingencies used to perform operational studies. Transmission operators are usually responsible for compiling the operational contingency lists for both normal and conservative operation. Therefore, we direct the ERO to modify MOD-010-0 to include transmission operators as an applicable entity. Consideration of Issue or Directive For operations, the sharing of contingencies is covered by MOD-001-1a, and for planning, TPL-001-4 requires lists of Contingencies be compiled in Requirements R3 and R4 as part of the required planning assessments in that standard. Those planning assessments must be distributed to adjacent PCs and TPs, and to any other functional entity with a reliability need, addressing the directives’ focus related to access to information by planners in paragraphs 1148, 1154, 1178, and 1183. Transmission Operator has also been added as an applicable entity in MOD-032-1.

Para 1155 We adopt our NOPR proposal that the planning authority should be included in this Reliability Standard because the planning authority is the entity responsible for the coordination and integration of transmission facilities and resource plans, as well as one of the entities responsible for the integrity and consistency of the data. We disagree with APPA that it is duplicative and unnecessary to require the planning authority to provide all of this information. However, we direct the ERO, as the entity charged with developing Reliability Standards, to address all of these concerns and to develop a consensus standard using its Reliability Standard development process. Consideration of Issue or Directive The Planning Authority plays an integral role in the standard modifications, both receiving data from the respective data owners, submitting data for its planning area to support the interconnection models, and validating models relative to their planning areas. The referenced attachment 1 specifies the specific “at a minimum” data for steady-state, dynamics, and short circuit data, establishing a level of consistency of data to support larger-scale, interconnection-specific models. However, the standard also recognizes that operational disparities may exist across North America, providing sufficient flexibility for Planning Coordinators to specify format and cases most appropriate to their specific circumstances and interconnection.

Outstanding Directives from FERC Order 693


Para 1662 We reiterate our position stated in the NOPR that the planning authority should be included in this Reliability Standard because the planning authority is the entity responsible for the coordination and integration of transmission facilities and resource planning, as well as one of the entities responsible for the integrity and consistency of the data. Therefore, we direct the ERO to add the planning authority to the applicability section of this Reliability Standard. Consideration of Issue or Directive See the response to Paragraph 1155.

Para 1178 Supported by several commenters, we adopt the NOPR proposal and direct the ERO to modify MOD-012-0 by adding a new requirement to provide a list of the faults and disturbances used in performing dynamics system studies for system operation and planning. We believe that access to such information will enable planners to accurately study the effects of disturbances occurring in neighboring systems on their own systems, which will benefit reliability. This requirement will also make transmission planning data more transparent, consistent with Order No. 890, which calls for greater openness of the transmission planning process on a regional basis. Consideration of Issue or Directive For operations, the sharing of contingencies is covered by MOD-001-1a, and for planning, TPL-001-4 requires lists of Contingencies be compiled in Requirements R3 and R4 as part of the required planning assessments in that standard. Those planning assessments must be distributed to adjacent PCs and TPs, and to any other functional entity with a reliability need, addressing the directives’ focus related to access to information by planners in paragraphs 1148, 1154, 1178, and 1183.

Para 1183 We agree with APPA that the functional entity responsible for providing the fault and disturbance list should be the transmission planner, instead of the transmission owner, as proposed in the NOPR. We also agree with APPA that the transmission operator should be added to the list of applicable entities in the Reliability Standards development process. Therefore, we direct the ERO to modify MOD-012-0 to require the transmission planner to provide fault and disturbance lists. Consideration of Issue or Directive For operations, the sharing of contingencies is covered by MOD-001-1a, and for planning, TPL-001-4 requires lists of Contingencies be compiled in Requirements R3 and R4 as part of the required planning assessments in that standard. Those planning assessments must be distributed to adjacent PCs and TPs, and to any other functional entity with a reliability need, addressing the directives’ focus related to access to information by planners in paragraphs 1148, 1154, 1178, and 1183. For the second part of the directive, the Transmission Operator has been added as an applicable entity in MOD-032-1.

Para 1184 We adopt our NOPR proposal that planning authorities should be included in this Reliability Standard because the planning authority is the entity responsible for the coordination and integration of transmission facilities and resource plans, as well as one of the entities responsible for the integrity and consistency of the data. We therefore direct the ERO to add the planning authority to the list of applicable entities. Consideration of Issue or Directive See response to paragraph 1155.



Para 1197 We agree with many commenters and direct the ERO to modify the Reliability Standard to permit entities to estimate dynamics data if they are unable to obtain unit specific data for any reason, not just for units constructed prior to 1990. Achieving the most accurate possible picture of the dynamic behavior of the Interconnection requires the use of actual data. We disagree with FirstEnergy and EEI and reject the 1990 cut-off date, because the age of the unit alone may not be the only reason why unit-specific data is unavailable. We agree with the Small Entities Forum that the Reliability Standard should include Requirements that such estimates be based on sound engineering principles and be subject to technical review and approval of any estimates at the regional level. That said, the Commission directs that this Reliability Standard be modified to require that the results of these dynamics models be compared with actual disturbance data to verify the accuracy of the models. Consideration of Issue or Directive This paragraph was clarified in FERC Order 693-A, paragraph 131, which stated “that ‘[a]chieving the most accurate possible picture of the dynamic behavior of the Interconnection requires the use of actual data,’” but acknowledges “that, in certain circumstances, actual data may not be initially available and only obtained through ‘verification of the dynamic models with actual disturbance data.’” This is being addressed by MOD-032-1, Requirement R4, which provides a mechanism to obtain more accurate information and data in cases where the initial data provided has technical or accuracy concerns. Furthermore, MOD-033-1 requires comparison of actual disturbance data to verify accuracy of dynamics models.

Para 1199 We adopt our NOPR proposal and direct the ERO to expand the applicability section in this Reliability Standard to include planning authorities because they are the entities responsible for the coordination and integration of transmission facilities and resource plans, as well as one of the entities responsible for the integrity and consistency of the data. Consideration of Issue or Directive See response to paragraph 1155.

Para 1210 We maintain our position set forth in the NOPR that analysis of the Interconnection system behavior requires the use of accurate steady-state models. Therefore, we direct the ERO to modify the Reliability Standard to include a requirement that the models be validated against actual system responses. We understand that NERC is incorporating recommendations from the Blackout Report and developing models for the Eastern Interconnection. Consideration of Issue or Directive Standard MOD-033-1 addresses this directive, adding a validation process requirement for PCs aimed specifically at ensuring models are validated against actual system responses. Model validation for individual generators and/or power plants is already required by Reliability Standards MOD-025-2, MOD-026-1, and MOD-027-1.

Para 1211 Further, the maximum discrepancy between the model results and the actual system response should be specified in the Reliability Standard. The Commission believes that the maximum discrepancy between the actual system performance and the model should be small enough that decisions made by planning entities based on output from the model would be consistent with the decisions of operating entities based on actual system response. We direct the ERO to modify MOD-014-0 through the Reliability Standards development process to require that actual system events be simulated and if the model output is not within the accuracy required, the model shall be modified to achieve the necessary accuracy. Consideration of Issue or Directive Similar to the consideration of paragraph 1210, Standard MOD-033-1, Requirement 1.1 addresses this directive, adding a validation process requirement for PCs that requires validation through simulation to ensure that the maximum discrepancy



between actual system performance and the model do not exceed the point where decisions made by the Planning Coordinator based on output from the model would be inconsistent with actual system response. In addition, the drafting team determined not to specify numeric accuracy thresholds in the standard itself. For instance, specifying percent for accuracy purposes is potentially problematic, as it may unintentionally exaggerate the degree of mismatch (e.g., 10 MW v. 20 MW (100% error) on a 345 KV line is not generally significant).

Para 1220 We maintain our position set forth in the NOPR that the analysis of Interconnection system behavior requires the use of accurate dynamics system models. Therefore, we direct the ERO to modify the Reliability Standard to include a requirement that the models be validated against actual system responses. We agree with EEI and NRC and confirm our position that a requirement to verify that dynamics system models are accurate should be a part of this Reliability Standard. We agree with EEI that this new requirement should be related to using the models to replicate events that occur on the system instead of developing separate testing procedures to verify the models. We direct the ERO to modify the standard to require actual system events be simulated and dynamics system model output be validated against actual system responses. Consideration of Issue or Directive See response to paragraph 1210.


Conclusion The informal development for the MOD B initiative provided key input into the proposed MOD B NERC Reliability Standards. In conjunction with the informal outreach, discussions, presentations, and technical conferences, the MOD B informal effort was able to begin addressing issues early. Informal outreach provided an efficient and open venue to consider myriad perspectives, build consensus, and engage in important dialogue. The result is a set of two new MOD reliability standards that represent input from virtually every corner of the electric industry, and time, effort, and discussion spent on upfront informal development was instrumental in quickly resolving points that may have otherwise taken significantly more time during formal development.


Appendix A: Entity Participants The below entities represent a non-exhaustive list of entities that had personnel that participated in the MOD B informal development effort in some manner, which may include one of the following: direct participation on the ad-hoc group, inclusion on the wider distribution (the “plus” list), attendance at workshops or other technical discussions, participation in a webinar or teleconference, or by providing feedback to the group through a variety of methods (e.g., email, phone calls, etc.). Additionally, though not listed here, announcements were distributed to wider NERC distribution lists to provide the opportunity for entities that were not actively participating to join the effort.

Table 1: Entity Participation in MOD B Informal Development

ACES Power Comed GTC MISO Seminole Electric

AECI ConEd Hydro Quebec MPW Sempra Utilities

AEP CPS IESO National Grid SF Water

Alcoa CPS Energy IID NaturEner SMUD

Ameren CSU IMEA NIPSCO Southern Company

APS Delmarva ISONE Northeast Utilities SPP RC

ATC Dominion ITC Northwestern SRP Regional Entities

Austin Energy Duke JEA NYISO Sunflower FRCC

Avista Duquesne Light KCPL NYPA SW Transco MRO

BC Hydro Dynegy KEPCO ODEC TEP NPCC

BEPC EKPC LBWL OGE Trans Bay Cable RFC

Black Hills Corp Entegra LCPUD OMPA Tres Amigas LLC SERC

BPA Entergy LCRA OTPCO TVA SPP

Brazos Electric ERCOT LGE & KU PacifiCorp Vectren TRE Centerpoint

Energy Exelon Lonestar

Transmission Pepco WAPA WECC

City of Glendale FMPA Luminant PGE We Energies

City of Tacoma Fortis BC MAPP PPL WECC RC

CMS Energy FPL MEAG Power PSEG Westar

Cogentrix GRDA MGE Quanta Technology Wisconsin Public

Service

Columbia Grid GRE MidAmerican SaskPower WPSCI

SCE Xcel Energy

Appendix A: Entity Participants


Table 2: Presentations and Events

EPRI Power Plant meeting North American Transmission Forum (NATF)

Modeling Practices Group (MPG)

ERAG Management Committee NPCC Compliance and Standards Spring Workshop

ERAG Multi-regional Modeling Working Group (MMWG)

NPCC Regional Standards Committee

GE PSLF users group NPCC’s Base Case Development working group (SS-

37)

MRO Model Building Subcommittee Siemens PSS/E Users Group

MRO Reliability Workshop Southern-Florida Planning Group

NERC Modeling Working Group Southwest Power Pool (SPP) Model Development

Working Group (MDWG)

NERC NEWS Various Regional Operating Committee

NERC Operating Committee Various Regional Planning Committees,

NERC Planning Committee Various Regional Standards Committees

NERC Planning Committee’s System Analysis and Modeling Subcommittee (SAMS)

WECC Modeling & Validation WG


Proposed Timeline for the

Project 2010-03 Standard Drafting Team (SDT) Anticipated Date Location Event

July 2013 - SC Authorizes SAR and Pro-forma Standards for Posting

July 2013

Conduct Nominations for Project 2010-03 SDT

July 2013 - Post SAR and Pro-forma Standards for 45-Day Comment

Period

August 2013 - Conduct Ballot

September 2013 - 45-Day Comment Period and Ballot Closes

September 2013 TBD MOD B Standard Drafting Team Face to Face Meeting to Respond to Respond to Initial Comments and Revise as

Necessary

September 2013 - Conduct Final Ballot

November 7, 2013 - NERC Board of Trustees Adoption

December 31, 2013 - NERC Files Petition with the Applicable Governmental

Authorities


July 18, 2013

MOD C Informal Development Project Requested Action

1. Authorize the concurrent posting of the MOD C Standards Authorization Request (SAR) for a 45-day informal comment period (given it is addressing FERC directives) along with the revised MOD C reliability standard (proposed MOD-031-1), VRFs/VSLs, and associated implementation plan for a 45-day comment period with a ballot pool formed during the first 30 days of the comment period, and a ballot and non-binding poll conducted during the last ten days of that comment period; and

2. Approve the posting for a 10-day solicitation for nominations for Standard Drafting Team members for MOD C’s formal development.

The MOD C project is assigned project number 2010-04. Background On March 16, 2007, FERC issued Order No. 693, Mandatory Reliability Standards for the Bulk-Power System. In this order, FERC issued 11 directives to make modifications to MOD-016-1.1, MOD-017-0.1, MOD-018-0, MOD-019-0.1, and MOD-021-1. MOD-020 will not be modified under this project. The MOD C initiative began informal development in February 2013. Specifically, the ad hoc group engaged stakeholders on how best to address the FERC directives, paragraph 81 candidates and results-based approaches. A discussion of the ad hoc group’s consensus building and collaborative activities are included in the Technical White Paper (see SAR package). Based on stakeholder outreach, the MOD C ad hoc group has developed one revised pro forma standard that addresses the FERC directives and recommendations for improving MOD-016 through MOD-019 and MOD-021, which included creating results-based requirements and considering paragraph 81 criteria to ensure that the standards proposals did not include requirements that meet those criteria. The existing MOD C standards are proposed to be retired. The goal is to present a final standard to the NERC Board of Trustees during its November meeting, and the Board adopted standard would then be filed with the applicable regulatory authorities by the end of 2013. Standard Drafting Team Consistent with the Standards Process Improvement Group (SPIG), it is proposed that the MOD C Standard Drafting Team be comprised of 8-10 members. Since this project is a continuation of informal development, several drafting team members will be selected from members of the informal group and the remainder from industry. A confidential slate of candidates with recommendations for appointment will be provided following the public solicitation. The purpose of this appointment/solicitation approach is to ensure a smooth transition from the informal to formal standards development process for MOD C, while also providing an


July 18, 2013 opportunity for solicitation of new members to help provide a well-rounded perspective to moving MOD C forward. The public solicitation shall request that standard drafting team members have experience in one or more of the following areas: transmission operations, transmission planning, operations planning, and resource planning. In addition, team members with experience in compliance, legal, regulatory and technical writing is desired. Previous drafting team experience is beneficial, but not a requirement. Quality Review A quality review was coordinated by NERC staff for the posting of the MOD C reliability standard, implementation plan, VRFs and VSLs. Project Schedule The drafting team is expected to facilitate meeting the proposed schedule contained in the SAR package.

MOD C SAR Package Submittal to the


July 18, 2013



MOD C Standards Committee Package - Contents Bookmark Description


Request

An informal development ad hoc group is presenting a pro forma standard that consolidates the existing MOD-016-1.1, MOD-017-0.1, MOD-018-0, MOD-019-0.1, and MOD-021-1 into a single standard. This standard provides a means of ensuring data will be collected and shared among the necessary parties (LSEs, BAs, TPs, etc.) in both the United States and Canada.

Pro Forma Standard

The pro forma standard is the result of the consolidation of the reliability-related components from the existing MOD C standards. The pro forma standard requirements are currently placed within a new standard, MOD-031-1.

Compliance Input The informal ad hoc group engaged NERC Compliance as to the pro forma for feedback and suggestions.

Implementation Plan

The implementation plan gives the overview of how the retirement of the existing standards will be tied to the effective date of the pro forma standard.

Mapping Document

The mapping document correlates the requirements within the existing MOD C standards to the requirements within the pro forma. If the requirements within the existing MOD C standards do not map to a requirement within the pro forma, a justification is supplied.

Technical White Paper

The purpose of this white paper is to provide background and technical rationale for the proposed revisions to the group of approved MOD standards that have a common mission of collecting data used in the analysis of resource needs.


The proposed timeline for the formal development gives estimates for face to face meetings, conference calls, and starting and end dates for various postings, along with the Board of Trustees meeting in November and the expecting filing date by December 31, 2013.


NERC welcomes suggestions to improve the

reliability of the bulk power system through

improved reliability standards. Please use this form

to submit your request to propose a new or a

revision to a NERC’s Reliability Standard.


Title of Proposed Standard: Demand Data

Date Submitted: July 18, 2013


Name: Darrel Richardson

Organization: NERC



New Standard



Urgent Action

SAR Information


Resolve FERC directives, incorporate lessons learned, update standards, and to incorporate initiatives

such as results-based, performance-based, Paragraph 81, etc.

Purpose or Goal (How does this request propose to address the problem described above?):

The pro forma standard consolidates the reliability components of the existing standards.

When completed, please email this form to:

[email protected]

mailto:[email protected]


Project 2010-04 Demand Data

July 18, 2013 2

SAR Information

Identify the Objectives of the proposed standard’s requirements (What specific reliability deliverables

are required to achieve the goal?):

The objectives are to address the outstanding directives from FERC Order 693, remove ambiguity from

the requirements, and incorporate lessons learned.


An informal development ad hoc group is presenting a pro forma standard that consolidates the existing MOD-016-1.1, MOD-017-0.1, MOD-018-0, MOD-019-0.1 and MOD-021-1 into a single standard. The collection of demand projections requires coordination and collaboration between Planning Authorities (also referred to as “Planning Coordinators”), Transmission and Resource Planners, and Load-Serving Entities. Ensuring that planners and operators have access to complete and accurate load forecasts – as well as the supporting methods and assumptions used to develop these forecasts – will enhance the reliability of the BPS. Collection of actual demand and demand-side management performance during the prior year will allow for comparison to prior forecasts and further contribute to enhanced accuracy of load forecasting practices. The pro forma standard requirements are currently placed within a new standard, MOD-031-1.





Detailed description of this project can be found in the Technical White Paper of this SAR submittal

package.




Organization










July 18, 2013 3


Balancing Authority














Provider



tariff).


Transmission

Operator





Generator Operator Operates generation unit(s) to provide real and reactive power.

Purchasing-Selling

Entity

Purchases or sells energy, capacity, and necessary reliability-related

services as required.







July 18, 2013 4






defined limits through the balancing of real and reactive power supply and demand.













Principles?

Enter

(yes/no)


Yes


Yes


Yes


Yes

Related Standards


MOD-001-1a Available Transmission System Capability



July 18, 2013 5

Related Standards

MOD-016-1.1 Documentation of Data Reporting Requirements for Actual and Forecast

Demands, Net Energy for Load, Controllable Demand-Side Management

MOD-017-0.1 Aggregated Actual and Forecast Demands and Net Energy for Load

MOD-018-0 Treatment of Nonmember Demand Data and How Uncertainties are Addressed

in the Forecasts of Demand and Net Energy for Load

MOD-019-0.1 Reporting of Interruptible Demands and Direct Control Load Management

MOD-021-1 Documentation of the Accounting Methodology for the Effects of Demand-Side

Management in Demand and Energy Forecasts

Related SARs

SAR ID Explanation

Regional Variances

Region Explanation

ERCOT None

FRCC None

MRO None



July 18, 2013 6

Regional Variances

NPCC None

RFC None

SERC None

SPP None

WECC None

MOD-031-1 — Demand Data

Draft #1: July 18, 2013 Page 1 of 11


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.

Description of Current Draft This is the first posting of the proposed draft standard. This proposed draft standard will be

posted for a 45‐day formal comment period.


45-day SAR Informal Comment Period July/August 2013

45-day Comment Period with Parallel Initial Ballot July/August 2013

Recirculation ballot October 2013




Effective Dates

MOD-031-1 shall become effective on the first day of the first calendar quarter that is twelve

months beyond the date that this standard is approved by applicable regulatory authorities.

In those jurisdictions where regulatory approval is not required, MOD-031-1 shall become

effective on the first day of the first calendar quarter that is twelve months beyond the date this

standard is approved by the NERC Board of Trustees, or as otherwise made effective pursuant to

the laws applicable to such ERO governmental authorities.

Version History


1 TBD Adopt MOD-031-1



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, these defined terms will be removed from the individual

standard and added to the Glossary.

Demand Side Management: The term for all activities or programs undertaken by any

applicable entity to influence the amount or timing of electricity they use.



When this standard has received ballot approval, the text boxes will be moved to the Application

Guidelines Section of the Standard.

A. Introduction

1. Title: Demand Data


3. Purpose: To ensure that actual and forecast Demand data necessary for assessment

and validation of past events and to support future system assessment is reported.

4. Applicability:


4.1.1 Planning Authority/Planning Coordinator (hereafter collectively referred

to as the “Planning Coordinator”)

This proposed standard combines “Planning Authority” with “Planning

Coordinator” in the list of applicable functional entities. The NERC

Functional Model lists “Planning Coordinator” while the registration

criteria list “Planning Authority,” and they are not yet synchronized. Until

that occurs, the proposed standard applies to “Planning Authority or

Planning Coordinator.”

4.1.2 Transmission Planner

4.1.3 Balancing Authority

4.1.4 Resource Planner

4.1.5 Load-Serving Entity

4.1.6 Distribution Provider

5. Background:

The fundamental test for determining the adequacy of the Bulk Power System (BPS) is

to determine the amount of resources and the certainty of these resources to be

available to serve peak demand while maintaining sufficient margin to address

operating events. This test requires the collection and aggregation of demand forecasts

on a normalized basis. This is defined as a forecast that has been adjusted to reflect

normal weather conditions, and is expected on a 50% probability basis – also known as

a 50/50 forecast (i.e. there is a 50% probability that the actual peak realized will be

either under or over the projected peak). This forecast can then be used to test against

more extreme conditions.

The collection of demand projections requires coordination and collaboration between

Planning Authorities (Planning Coordinators), Transmission and Resource Planners,

and Load-Serving Entities. Ensuring that planners and operators have access to

complete and accurate load forecasts – as well as the supporting methods and

assumptions used to develop these forecasts – will ultimately enhance the reliability of

the BPS. Consistent documenting and information sharing activities will also improve



efficient planning practices and support the identification of needed system

reinforcements. Furthermore, collection of actual demand and demand-side

management performance during the prior year will allow for comparison to prior

forecasts and further contribute to enhanced accuracy of load forecasting practices.


R1. The Planning Coordinator or Balancing Authority, as identified by the Regional Entity

in a data request, shall develop and issue a data reporting request associated with a data

request issued by the Regional Entity. This data reporting request shall include, at a

minimum: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

1.1. A list of Transmission Planners, Balancing Authorities, Load Serving Entities,

and Distribution Providers that are required to provide the data (“Applicable

Entity”).

1.2. A schedule detailing the timetable for providing the data. (A minimum of 30-

days must be allowed for responding to the request).

1.3. The original data request from the Regional Entity.

1.4. A request for the following actual data1:

1.4.1. Integrated hourly demands in megawatts (MW) for the prior year.

1.4.2. Monthly and annual peak hour actual demands in MW and Net Energy for

Load in gigawatthours (GWh) for the prior year.

1.4.3. Monthly and annual peak hour weather normalized actual demands in MW

for the prior year.

1.4.4. Monthly and annual peak hour deployed Interruptible Load and Direct

Control Load Management in MW for the prior year.

1.5. A request for the following forecast data1:

1.5.1. Monthly peak hour forecast demands in MW and Net Energy for Load in

GWh for the next two years.

1.5.2. Peak hour forecast demands (summer and winter) in MW and annual Net

Energy for load in GWh for ten years into the future.

1 This could include data reported in the Long Term Reliability Assessment (LTRA) and the EIA 411.

Rationale for R1: To ensure when Planning Coordinators (PC) or Balancing Authorities

request data (R1), they identify the entities to provide the data (responsible entity in R1.1),

that the entities providing the data know what they are to provide (R 1.3 – R 1.7) and the

due dates (R 1.2) for the requested data.



1.5.3. Forecasts of Interruptible Load and Direct Control Load Management

(DCLM) for at least five years and up to ten years into the future, as

requested, for summer and winter peak system conditions.

1.6. A requirement for Applicable Entities to identify registered entities that are within

their footprint but are not a member of the requesting Region, and identify the

Region where the data for that registered entity is reported.

1.7. A requirement for Applicable Entities to provide:

1.7.1. The assumptions and methods used in the development of aggregated peak

demand and Net Energy for Load forecasts.

1.7.2. The Demand and energy effects of Interruptible and Direct Control Load

Management.

1.7.3. How DSM measures are addressed in the forecasts of its Peak Demand

and annual Net Energy for Load.

1.7.4. How the peak load forecast compares to actual load for the prior year with

due regard to controllable load2, temperature and humidity variations and,

if applicable, how the assumptions and methods for future forecasts were

adjusted.

M1. The Planning Coordinator or Balancing Authority as identified by the Regional Entity

in its data request, shall have a dated data reporting request, either in hardcopy or

electronic format, in accordance with Requirement R1.

R2. Each Applicable Entity shall provide the data in accordance with the data reporting

request in Requirement R1 to the Planning Coordinator or Balancing Authority or any

other entity (such as Load Serving Entity, Planning Coordinator or Resource Planner)

on request. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning ]

M2. Each Applicable Entity shall have evidence such as dated e-mail or dated transmittal

letters that it provided the data requested in accordance with Requirement R2.

2 For the purpose of this standard, the term “controllable load” means both interruptible load and direct control load

management as referenced in FERC Order 693 Para 1267.

Rationale for R3: This will ensure that the Planning Coordinator or when applicable, the

Balancing Authority, provides the data requested by the Regional Entity.

Rationale for R2: This will ensure that entities identified in Requirement R1, that are

responsible for providing data, provide the data in accordance with the details described

in the data reporting procedure developed in Requirement R1. The sharing of

documentation of the supporting methods and assumptions used to develop forecasts as

well as information-sharing activities will improve the efficiency of planning practices

and support the identification of needed system reinforcements.



R3. The entity identified by the Regional Entity in its data request, shall report the

Applicable Entity’s data as requested by the Regional Entity within the timeframe

specified in the Regional Entity’s request. [Violation Risk Factor: Medium] [Time

Horizon: Long-term Planning ]

M3. Each entity identified by the Regional Entity in its data request, shall have evidence

such as dated e-mail or dated transmittal letters that it provided the data requested in

accordance with Requirement R3.

C. Compliance 1. Compliance Monitoring Process


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.


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 Applicable Entity shall keep data or evidence to show compliance with

Requirements R1 through R3, and Measures M1 through M3, since the last audit,

unless directed by its Compliance Enforcement Authority to retain specific

evidence for a longer period of time as part of an investigation.

If an Applicable Entity is found non-compliant, it shall keep information related

to the non-compliance until mitigation is complete and approved, or for the time

specified above, whichever is longer.

The Compliance Enforcement Authority shall keep the last audit records and all

requested and submitted subsequent audit records.


Refer to the NERC Rules of Procedure for the Compliance Monitoring and

Assessment processes.


None


Draft 1: July 18, 2013 Page 8 of 11


R # Time Horizon

VRF Violation Severity Levels


R1 Long-term

Planning

Medium The Planning

Coordinator or Balancing

Authority, as identified

by the Regional Entity,

developed a data

reporting procedure but

failed to address one of

the items listed in

Requirement R1, Part 1.6

or Part 1.7.1 through Part

1.7.4.

The Planning




developed a data


failed to address two of

the items listed in



1.7.4.

OR

The Planning




developed a data


failed to address one of

the items listed in


through Part 1.3, Part

1.4.1, Part 1.4.2 or Part

1.5.1 through Part 1.5.3.

The Planning




developed a data


failed to address three of

the items listed in



1.7.4.

OR

The Planning




developed a data


failed to address two of

the items listed in


through Part 1.3, Part

1.4.1, 1.4.2 or Part 1.5.1

through Part 1.5.3.

The Planning Coordinator

or Balancing Authority, as

identified by the Regional

Entity, did not develop a

data reporting procedure.

OR


or Balancing Authority, as


Entity, developed a data


failed to issue the data

reporting request to the

Applicable Entities

identified in Requirement

R1 Part 1.1.

OR


or Balancing Authority as




failed to address any of the

items listed in Requirement

R1, Part 1.6 or Part 1.7.1

through Part 1.7.4.

OR




or Balancing Authority as




failed to address three or

more of the items listed in


through 1.3, Part 1.4.1, Part

1.4.2, or Part 1.5.1 through

Part 1.5.3.

R2 Long-term

Planning

Medium N/A N/A N/A The Applicable Entity, as

defined in the data reporting

request developed in

Requirement R1, failed to

provide the data requested

to the requesting entity as

defined in Requirement R1.

R3 Long-term

Planning

Medium N/A N/A N/A The entity as identified by

the Regional Entity in its

data request, failed to

provide the data requested

by the Regional Entity.



D. Regional Variances None.

E. Interpretations None.

F. Associated Documents None.




Requirement R1:

Requirement R2:

Requirement R3:

Compliance Operations Draft Reliability Standard Compliance Guidance for MOD-031-1 July 3, 2013 Introduction

The NERC Compliance department (Compliance) worked with the MOD C informal ad hoc group (MOD C Group) in a review of pro forma standard MOD-031-1. The purpose of the review is to discuss the requirements of the pro forma standard to obtain an understanding of its intended purpose and necessary evidence to support compliance. The purpose of this document is to address specific questions posed by the MOD C Group and Compliance in order to aid the drafting of the requirements and provide a level of understanding regarding evidentiary support necessary to demonstrate compliance. While all testing requires levels of auditor judgment, participating in these reviews allows Compliance to develop training and approaches to support a high level of consistency in audits conducted by the Regional Entities. However, this document makes no assessment as to the enforceability of the standard. The following questions will both assist the MOD C Group in further refining the standard and be used to aid in the development of auditor training. MOD-031-1 Questions

Question 1 In Requirement R2, will the auditor verify that the data was delivered as specified or will the auditor make a determination regarding whether the quality of the data is sufficient? Compliance Response to Question 1 Based on the language in the requirement and the purpose of the standard, which is to facilitate the sharing of data, the auditor should only verify that the data was delivered as specified. This standard does not specify criteria around quality, so auditors should not make any assessments in that regard. Conclusion

In general, Compliance finds the pro forma standard provides a reasonable level of guidance for Compliance Auditors to conduct audits in a consistant manner. The standard establishes timelines, data requirements, and ownership of specific actions. Further, the review of the standard enables Compliance to develop training for Compliance Auditors to execute their reviews. However, Compliance does recommend the MOD C Group consider the item(s) noted in the response to the question.

Following final approval of the Reliability Standard, Compliance will develop the final Reliability Standards Auditor Worksheet (RSAW) and associated training. Attachment A represents the version of the pro forma standard requirements referenced in this document.

Draft Reliability Standard Compliance Guidance for MOD-031-1 July 2, 2013 2

Attachment A


R1. The Planning Coordinator or Balancing Authority as identified by the Regional Entity in a data request, shall develop and issue a data reporting request associated with a data request issued by the Regional Entity. This data reporting request shall include, at a minimum: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

1.1. A list of Transmission Planners, Balancing Authorities, Load Serving Entities and Distribution Providers that are required to provide the data (“Applicable Entity”).

1.2. A schedule detailing the timetable for providing the data. (Note: a minimum of 30-days must be allowed for responding to the request).

1.3. The original data request from the Regional Entity.

1.4. A request for the following actual data1:

1.4.1. Integrated hourly demands in megawatts (MW) for the prior year.

1.4.2. Monthly and annual peak hour actual demands in MW and Net Energy for Load in gigawatthours (GWh) for the prior year.

1.4.3. Monthly and annual peak hour weather normalized actual demands in megawatts (MW) for the prior year.

1.4.4. Monthly and annual peak hour deployed Interruptible Load and Direct Control Load Management in megawatts (MW) for the prior year.

1.5. A request for the following forecast data1:

1.5.1. Monthly peak hour forecast demands in MW and Net Energy for Load in GWh for the next two years.

1.5.2. Peak hour forecast demands (summer and winter) in MW and annual Net Energy for load in GWh for ten years into the future.

1.5.3. Forecasts of Interruptible Load and Direct Control Load Management (DCLM) for at least five years and up to ten years into the future, as requested, for summer and winter peak system conditions.

1.6. A requirement for Applicable Entities to identify registered entities that are within their footprint but are not a member of the requesting Region, and identify the Region where the data for that registered entity is reported.

1.7. A requirement for Applicable Entities to provide:

1.7.1. The assumptions and methods used in the development of aggregated peak demand and Net Energy for Load forecasts.

1 This could include data reported in the Long Term Reliability Assessment (LTRA) and the EIA 411.

Draft Reliability Standard Compliance Guidance for MOD-031-1 July 2, 2013 3

1.7.2. The Demand and energy effects of Interruptible and Direct Control Load Management.How DSM measures are addressed in the forecasts of its Peak Demand and annual Net Energy for Load.

1.7.3. How the peak load forecast compares to actual load for the prior year with due regard to controllable load2, temperature and humidity variations and, if applicable, how the assumptions and methods for future forecasts were adjusted.

M1. The Planning Coordinator or Balancing Authority as identified by the Regional Entity in its data request, shall have a dated data reporting request, either in hardcopy or electronic format, in accordance with Requirement R1.

R2. Each Applicable Entity shall provide the data in accordance with the data reporting request in Requirement R1 to the Planning Coordinator or Balancing Authority or any other entity (such as Load Serving Entity, Planning Coordinator or Resource Planner) on request. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning ]

M2. Each Applicable Entity shall have evidence such as dated e-mail or dated transmittal letters that it provided the data requested in accordance with Requirement R2.

R3. The entity identified by the Regional Entity in its data request, shall report the Applicable Entities’ data as requested by the Regional Entity within the timeframe specified in the Regional Entity’s request. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning ]

M3. Each entity identified by the Regional Entity in its data request, shall have evidence such as dated e-mail or dated transmittal letters that it provided the data requested in accordance with Requirement R3.

2 For the purpose of this standard, the term “controllable load” shall refer to both interruptible load and direct control load management as

referenced in FERC Order 693 Para 1267.

Implementation Plan Project 2010-04 Demand Data

Implementation Plan for MOD-031-1 – Demand Data

Approvals Required MOD-031-1 – Demand Data

Prerequisite Approvals There are no other standards that must receive approval prior to the approval of this standard.

Revisions to Glossary Terms Demand Side Management: The term for all activities or programs undertaken by any applicable entity to influence the amount or timing of electricity they use.

The proposed revised definition for “Demand-Side Management” is incorporated in the NERC approved standards, detailed in Attachment 1 of this document. After reviewing the standards incorporating the term “Demand-Side Management”, it is not anticipated that the proposed revision will have any adverse effect on the standards.

Applicable Entities

Planning Coordinator

Transmission Planner

Resource Planner

Balancing Authority

Load-Serving Entity

Distribution Provider Applicable Facilities N/A Conforming Changes to Other Standards None

Project 2010-04 Demand Data Implementation Plan July 18, 2013

2

Effective Dates

MOD-031-1 shall become effective as follows:

1. MOD-031-1 shall become effective on the first day of the first calendar quarter that is twelve months beyond the date that this standard is approved by applicable regulatory authorities.

2. In those jurisdictions where regulatory approval is not required, MOD-031-1 shall become effective on the first day of the first calendar quarter that is twelve months beyond the date this standard is approved by the NERC Board of Trustees, or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities.

Justification The 12-month implementation period will provide sufficient time for the applicable entities to develop the necessary process to implement this standard. Retirements MOD-016-1.1, MOD-017-0.1, MOD-018-0, MOD-019-0.1, and MOD-021-1 shall be retired upon MOD-031-1 becoming effective. The current definition of Demand Side Management (DSM) in the NERC Glossary of Terms shall be retired upon MOD-031-1 becoming effective.

Project 2010-04 Demand Data Implementation Plan July 18, 2013

3

Attachment 1 Approved Standards Incorporating the Term “Demand-Side Management”

BAL-502-RFC-02 — Planning Resource Adequacy Analysis, Assessment and Documentation EOP-002-3.1 — Capacity and Energy Emergencies IRO-006-EAST-1 — TLR Procedure for the Eastern Interconnection MOD-016-1.1 — Actual and Forecast Demands, Net Energy for Load, Controllable DSM MOD-017-0.1 — Aggregated Actual and Forecast Demands and Net Energy for Load MOD-018-0 — Reports of Actual and Forecast Demand Data MOD-019-0.1 — Forecasts of Interruptible Demands and DCLM Data MOD-020-0 — Providing Interruptible Demands and DCLM Data MOD-021-1 — Accounting Methodology for Effects of DSM in Forecasts

Approved Standards Pending Regulatory Approval Incorporating the Term “Demand-Side Management”

BAL-002-WECC-2 — Contingency Reserve TPL-001-2 — Transmission System Planning Performance Requirements TPL-001-3 — System Performance Under Normal Conditions TPL-001-4 — Transmission System Planning Performance Requirements TPL-002-2b — System Performance Following Loss of a Single BES Element TPL-003-2a — System Performance Following Loss of Two or More BES Elements TPL-003-2b — System Performance Following Loss of Two or More BES Elements TPL-004-2 — System Performance Following Extreme BES Events TPL-004-2a — System Performance Following Extreme BES Events TPL-006-0 — Assessment Data from Regional Reliability Organizations TPL-006-0.1 — Assessment Data from Regional Reliability Organizations

Project 2010-04 Mapping Document Transition of MOD-016-1.1, MOD-017-0.1, MOD-018-0, MOD-019-0.1, and MOD-021-1 to MOD-031-1 (the pro forma standard)

Standard: MOD-016-1.1 – Documentation of Data Reporting Requirements for Actual and Forecast Demands, Net Energy for Load, Controllable Demand-Side Management

Requirement in Approved Standard

Transitions to the below Requirement in New Standard or Other Action


MOD-016-1a R1 Requirement R1 The pro forma standard requires the Planning Coordinator or Balancing Authority to develop and issue a data reporting request.

MOD-016-1a R1.1 Requirement R1

MOD-010 through MOD-015 does not depend on these standards for their data (they collect the data needed). TPL-005 and TPL-006 are not FERC approved standards but the data is available for their use. The pro forma standard will require the Planning Coordinator or Balancing Authority to identify the format for providing data.

MOD-016-1a R2 Requirement R1 See comments on Requirement R1.

MOD-016-1a R2.1 Requirement R1 part 1.2 The pro forma standard requires the Planning Coordinator or Balancing Authority to provide a timeline for providing the data.

MOD-016-1a R3 Requirement R1 See comments on Requirement R1.

MOD-016-1a R3.1 Requirement R1 The Planning Coordinator or Balancing Authority must respond within the time allotted by the Electric Reliability Organization (ERO) or Regional Entity (RE).

2

Standard: MOD-017-0.1 – Aggregated Actual and Forecast Demands and Net Energy for Load




MOD-017-0.1 R1 Requirement R2 Requirement R2 of the pro forma standard will require entities to provide data as outlined in Requirement R1 parts 1.1 through 1.7.

MOD-017-0.1 R1.1 Requirement R1 part 1.4.1 The pro forma standard will require entities to provide integrated hourly demands in megawatts (MW) for the prior year.

MOD-017-0.1 R1.2 Requirement R1 part 1.4.2 The pro forma standard will require entities to provide monthly and annual peak hour actual demands in MW and Net Energy for Load in gigawatthours (GWh) for the prior year.

MOD-017-0.1 R1.3 Requirement R1 part 1.5.1 The pro forma standard will require entities to provide monthly peak hour forecast demands in MW and Net Energy for Load in GWh for the next two years.

MOD-017-0.1 R1.4 Requirement part R1 part 1.5.2 The pro forma standard will require entities to provide peak hour forecast demands (summer and winter) in MW and annual Net Energy for load in GWh for ten years into the future.

3

Standard: MOD-018-0 – Treatment of Nonmember Demand Data and How Uncertainties are Addressed in the Forecasts of Demand and Net

Energy for Load Requirement in

Approved Standard Transitions to the below Requirement in

New Standard or Other Action Description and Change Justification

MOD-018-0 R1 Omitted This requirement serves no direct purpose other than as a bridge to the sub-requirements below.

MOD-018-0 R1.1 Requirement R1 part 1.6

The pro forma standard will require entities to identify registered entities that are within their footprint but are not a member of the requesting Region, and identify the Region where the data for that registered entity is reported.

MOD-018-0 R1.2 Requirement R1 part 1.7.1 The pro forma standard will require entities to provide the assumptions and methods used in the development of aggregated peak demand and Net Energy for Load forecasts.

MOD-018-0 R1.3 Requirement R1 This is now a part of the data reporting request developed in Requirement R1.

MOD-018-0 R2 Requirement R2 The pro forma standard will require entities to provide the data requested in Requirement R1 parts 1.1 through 1.7.

4

Standard: MOD-019-0.1 – Reporting of Interruptible Demands and Direct Control Load Management




MOD-019-0.1 R1 Requirements R1 part 1.5.3

The pro forma standard will require entities to provide forecasts of Interruptible Load and Direct Control Load Management (DCLM) for at least five years and up to ten years into the future, as requested, for summer and winter peak system conditions.

Standard: MOD-021-1 – Documentation of the Accounting Methodology for the Effects of Demand-Side Management in Demand and Energy Forecasts




MOD-021-1 R1 Requirements R1 part 1.7.2 The pro forma standard will require entities to provide the Demand and energy effects of Interruptible and Direct Control Load Management.

MOD-021-1 R2 Requirements R1 part 1.7.3 The pro forma standard will require entities to provide how DSM measures are addressed in the forecasts of its Peak Demand and annual Net Energy for Load.

MOD-021-1 R3 Requirements R1 part 1.2 The pro forma standard will require entities to provide the requested data by a certain date.

NERC | MOD C White Paper | July 1, 2013 1 of 11

White Paper on the MOD C Standards MOD-016, MOD-017, MOD-018,

MOD-019, and MOD-021

July 18, 2013



NERC | MOD C White Paper | June 28, 2013 2 of 11

Table of Contents Table of Contents ......................................................................................................................................................................... 2 Executive Summary ..................................................................................................................................................................... 3 Purpose ........................................................................................................................................................................................ 4 Technical Discussion .................................................................................................................................................................... 5 Outstanding FERC Directives ....................................................................................................................................................... 6

Para 1232 ................................................................................................................................................................................. 6

Consideration of Directive ................................................................................................................................................... 6

Para 1249 ................................................................................................................................................................................. 6


Para 1250 ................................................................................................................................................................................. 7


Para 1251 ................................................................................................................................................................................. 7


Para 1252 ................................................................................................................................................................................. 7


Para 1255 ................................................................................................................................................................................. 7


Para 1256 ................................................................................................................................................................................. 8


Para 1265 ................................................................................................................................................................................. 8


Para 1276 ................................................................................................................................................................................. 8


Para 1277 ................................................................................................................................................................................. 8


Para 1298 ................................................................................................................................................................................. 8


Conclusion ................................................................................................................................................................................. 10 Appendix A: Entity Participants ................................................................................................................................................. 11


Executive Summary

NERC Reliability Standards MOD-016, -017, -018, -019, and -021 (referred to herein as the “MOD C” standards), were approved in the Federal Energy Regulatory Commission’s (“FERC” or “Commission”) Order No. 693. Collectively, the MOD C standards pertain to the collection of data necessary to analyze the resource needs to serve peak demand while maintaining a sufficient margin to address operating events as follows:

MOD-016-1.1 is the umbrella standard that contains the documentation required for the data collection requirements.

MOD-017-0.1 provides for the data requirements for actual and forecast peak demand and net energy for load.

MOD-018-0 provides for the treatment of nonmember demand data and how uncertainties are addressed in the

forecasts of demand and net energy for load.

MOD-019-0.1 provides for the collection of interruptible demands and direct control load management.

MOD-020-0 addresses the need to provide interruptible demands and direct control load management data to

System Operators and Reliability Coordinators.

MOD-021-1 provides for the documentation of how Demand-Side Management demands are accounted for in demand and energy forecasts.

NERC initiated an informal development process to address directives in Order No. 693 to modify certain aspects of the MOD C standards. The first informal meeting was held in February 2013 at NERC’s Washington, D.C. office. Participants were industry subject matter experts (SMEs), NERC staff, and staff from FERC’s Office of Electric Regulation. The small ad hoc group of SMEs participated in discussions about the outstanding FERC directives and possible resolutions to address the directives. The group also discussed the six standards (MOD-016 through MOD-021) and identified issues with the present standards. The group very quickly identified MOD-020 as dealing with the operational time frame and concluded that it should not be addressed with the other standards at this time since they were applicable to the planning horizon. Although a pure data reporting standard would be a candidate for retirement under Paragraph 81, the data being collected has a reliability purpose in the development of future assessments for resource adequacy. It was decided to present a pro forma standard that consolidates the remaining five MOD C standards into a single standard, which was supported as the group conducted informal development outreach. Creating a single standard provides a means of ensuring data will be collected and shared among the necessary parties (LSEs, BAs, TPs, etc.) in both the United States and Canada. As detailed below, the MOD C informal ad hoc group discussed the outstanding directives from FERC Order No. 693 and, through the informal development, provided a resolution to address each one.


Purpose

The purpose of this white paper is to provide background and technical rationale for the proposed revisions to the group of approved MOD standards that have a common mission of collecting data used in the analysis of resource needs. This document outlines the next generation of these standards and proposes to combine the reliability components of this package of standards into one standard. The remaining requirements in this package would either be retired as administrative or captured as instructional or explanatory in a white paper. This white paper lays out a common understanding of industry perspectives on topics included in these standards. It further provides an explanation of how NERC is addressing each of the outstanding FERC directives assigned to these FERC-approved standards. This paper will also provide technical justifications and support for the proposed requirements that are retained and placed into the pro forma standard. The contents of this paper are intended to assist the standard drafting team (SDT) assigned to MOD C and industry stakeholder participants with background information to move this standard package through the formal development process. Eventually, following industry and the NERC Board of Trustees’ adoption of the proposed standard, this white paper will be used to support the filing to the applicable regulatory authorities.


Technical Discussion

The fundamental test for determining the adequacy of the bulk power system (BPS) is to determine the amount of resources and the certainty of these resources to be available to serve peak demand while maintaining a sufficient margin to address operating events. This test requires the collection and aggregation of demand forecasts on a normalized basis. This is defined as a forecast that has been adjusted to reflect normal weather conditions and is expected on a 50 percent probability basis, also known as a 50/50 forecast (i.e., there is a 50 percent probability that the actual peak realized will be either under or over the projected peak). This forecast can then be used to test against more extreme conditions.

The collection of demand projections requires coordination and collaboration between Planning Authorities/Planning Coordinators, Transmission and Resource Planners, and Load-Serving Entities. Ensuring that planners and operators have access to complete and accurate load forecasts—as well as the supporting methods and assumptions used to develop these forecasts—will ultimately enhance the reliability of the BPS. Consistent documenting and information-sharing activities will also improve the efficiency of planning practices and support the identification of needed system reinforcements. Furthermore, collection of actual demand and Demand-Side Management performance during the prior year will allow for comparison to prior forecasts and further contribute to enhanced accuracy of load forecasting practices. The ad hoc group identified two options to address MOD-016 through MOD-019 and MOD-021. The first option was to retire the five standards and include the data being collected in the Long-Term Reliability Assessment (LTRA). The second option was to combine the five standards into a single standard with three or four clear requirements. Initially, the ad-hoc group suggested tying the standard to the LTRA. Currently, the majority of LTRA data is required for the completion of the Form EIA-411, administered by the Energy Information Administration (EIA). Accordingly, failure by the Regional Entities to provide this data to NERC on an annual basis is in violation of federal law. In the absence of a standard however, NERC has no ability to directly address an entity that fails to provide requested LTRA data. This especially applies for Canadian provinces that do not provide data for the Form EIA-411. A second alternative to addressing data requirements in the absence of a standard is the implementation of either a Section 800 or Section 1600 data request. This approach, while effective, has a number of disadvantages. First, some Canadian provinces are not subject to FERC rule, which makes it more difficult for NERC to enforce an 800 or 1600 data request. The second issue is with entities within the continental United States. The 800 or 1600 data request is not mandatory and does not provide a mechanism to compel participation other than pursuing federal action under Section 215 of the Federal Power Act. In addition, using either of these approaches does not provide a mechanism for other LSEs, DPs, BAs or TPs to obtain the data from a neighboring entity. The recommended option of modifying the existing standards to remove the ambiguity and address the FERC directives solves the issues identified with the first two options. Creating a single standard provides a means of ensuring data will be collected and shared among the necessary parties (LSEs, BAs, TPs, etc.) in both the United States and Canada. The informal development effort resulted in the recommendation for the development of a standard and has provided a draft version that combines the five existing standards into a single, comprehensive, and clear standard with three requirements.


Outstanding FERC Directives

There are 11 outstanding FERC directives from Order 693. Each of the directives was discussed in detail during the informal development stage, and summaries of the discussions can be found below. The ad hoc group extensively reviewed each of the directives with consideration of where the existing standards are today, where the group landed with the pro forma standard following its extensive industry outreach, and how the group addressed each directive. The “Paragraph 81 initiative,” which was issued by FERC in their March 15, 2012,

1 invited the ERO to identify possible

requirements that have little to no effect on reliability that could be removed from the NERC Reliability Standards. The ad hoc group took the information from the FERC order into consideration when it discussed the directives related to the MOD C initiative.

Para 1232 Supported by many commenters, the Commission directs the ERO to modify MOD-016-1 and expand the applicability section to include the transmission planner, on the basis that under the NERC Functional Model the transmission planner is responsible for collecting system modeling data, including actual and forecast load, to evaluate transmission expansion plans. We disagree with EEI that this Reliability Standard should not be applied to the transmission planner because load-related data for controllable DSM is not only needed for distribution and transmission operations, but is also necessary for the transmission planner to take controllable DSM into account in planning the transmission system. Requirement R1.1 relates to data submittal, and requires data to be consistent with that supplied for the TPL-005 and TPL-006 standards, which clearly apply to transmission planners. We approve the ERO’s definition in the glossary of DSM as “all activities or programs undertaken by a Load-Serving Entity or its customers to influence the amount or timing of electricity they use.” Only activities or programs that meet the ERO definition, with the modification directed below, may be treated as DSM for purposes of the Reliability Standards. Recognizing the potential role that industrial customers who do not take service through an LSE and load aggregators, for example, may play in meeting the Reliability Standards, we direct the ERO to modify the definition of DSM. Specifically, we direct the ERO to add to its definition of DSM “any other entities” that undertake activities or programs to influence the amount or timing of electricity they use without violating other Reliability Standard Requirement.

Consideration of Directive With regard to the first directive, the ad hoc group is recommending that the Transmission Planner be added to the Applicability Section of the proposed standard MOD-031-1 Demand Data Reporting. Regarding the second directive, the ad hoc group is proposing a modified definition for Demand-Side Management (DSM). However, the group felt that the FERC proposed definition needed further clarity, so they modified it in an equally effective and efficient manner. It now reads:

Demand-Side Management: The term for all activities or programs undertaken by any applicable entity to influence the amount or timing of electricity they use.

Para 1249 The Commission also directs the ERO to modify the Reliability Standard to require reporting of temperature and humidity along with peak load because actual load must be weather normalized for meaningful comparison with forecasted values. In response to MidAmerican’s observation that it sees little value in collecting this data, we believe that collecting it will allow all load data to be weather-normalized, which will provide greater confidence when comparing data accuracy, which ultimately will enhance reliability. As a result, we reject Xcel’s proposal that the standard be revised to include only the generic term “peak producing weather conditions” because it is too generic for a mandatory Reliability Standard.

1 http://www.nerc.com/files/OrderConditionallyAcceptingNewEnfocementMechFiling_031512.pdf

http://www.nerc.com/files/OrderConditionallyAcceptingNewEnfocementMechFiling_031512.pdf



Consideration of Directive The informal ad hoc group developed Requirement R1 of the proposed standard MOD-031-1 Demand Data Reporting. Requirement R1 now requires weather-normalized actual demand data to be reported (Requirement R1 part 1.4.3). The requirement now states that an entity must provide an explanation of how it used temperature and humidity to weather normalize its actual demands (Requirement R1 part 1.7.4).

Para 1250 We also reject Alcoa’s proposal that the reporting of temperature and humidity along with peak loads should apply only to load that varies with temperature and humidity because it essentially is a request for an exemption from the requirements of the Reliability Standard and should therefore be directed to the ERO as part of the Reliability Standards development process. We agree, however, with APPA that certain types of load are not sensitive to temperature and humidity. We therefore find that the ERO should address Alcoa’s concerns in its Reliability Standards development process.

Consideration of Directive The informal ad hoc group discussed this issue at length and decided that there should not be an exemption. The group believes that if the load is not weather-sensitive then an explanation will be provided (Requirement R1 part 1.7.4), which will accomplish the same objective as providing an exemption.

Para 1251 The Commission adopts the NOPR proposal directing the ERO to modify the Reliability Standard to require reporting of the accuracy, error and bias of load forecasts compared to actual loads with due regard to temperature and humidity variations. This requirement will measure the closeness of the load forecast to the actual value. We understand that load forecasting is a primary factor in achieving Reliable Operation. Underestimating load growth can result in insufficient or inadequate generation and transmission facilities, causing unreliability in real-time operations. Measuring the accuracy, error and bias of load forecasts is important information for system planners to include in their studies, and also improves load forecasts themselves.

Consideration of Directive The informal ad hoc group developed Requirement R1 of the proposed standard MOD-031-1 Demand Data Reporting. The requirement now states that an entity must provide an explanation of how the actual and forecast demand compared (Requirement R1 part 1.7.4).

Para 1252 The Commission agrees with APPA that accuracy, error and bias of load forecasts alone will not increase the reliability of load forecasts, and, as a result, will not affect system reliability. Understanding of the differences without action based on that understanding would not change anything. Therefore, we direct the ERO to add a Requirement that addresses correcting forecasts based on prior inaccuracies, errors and bias.

Consideration of Directive The informal ad hoc group developed Requirement R1 of the proposed standard MOD-031-1 Demand Data Reporting. The requirement now states that an entity must provide an explanation of how the assumptions and methods for future forecasts were adjusted (Requirement R1 part 1.7.4).

Para 1255 We agree with FirstEnergy that transmission planners should be added as reporting entities, and direct the ERO to modify the standard accordingly. We agree that in the NERC Functional Model, the transmission planner is responsible for collecting system modeling data including actual and forecast demands to evaluate transmission expansion plans.

Consideration of Directive The informal ad hoc group, as a result of its informal outreach, is recommending that the Transmission Planner be added to the Applicability Section of the proposed standard MOD-031-1 Demand Data Reporting.



Para 1256 The Commission disagrees in general with MISO’s recommendation to allow some exceptions to the requirement to provide hourly demand data. However, the metering for some customer classes may not be designed to provide certain types of data. The Commission therefore directs the ERO to consider MISO’s concerns in the Reliability Standards development process.

Consideration of Directive The informal ad hoc group discussed this issue at length with industry participants during informal outreach and decided that there should not be an exemption. The group believes that all load data should be reported to accurately model the Bulk Power System.

Para 1265 Regarding TAPS’s concern that small entities should not be required to comply with MOD-018-0 because their forecasts are not significant for system reliability purposes, the Commission directs the ERO to address this matter in the Reliability Standards development process.

Consideration of Directive The informal ad hoc group discussed this issue at length during its outreach and concluded that there should not be an exemption. The group believes that all load data should be reported to accurately model the Bulk Power System.

Para 1276 The Commission adopts the NOPR proposal directing the ERO to modify this standard to require reporting of the accuracy, error and bias of controllable load forecasts. This requirement will enable planners to get a more reliable picture of the amount of controllable load that is actually available, therefore allowing planners to conduct more accurate system reliability assessments. The Commission finds that controllable load can be as reliable as other resources, and therefore should also be subject to the same reporting requirements. Although we recognize that verifying load control devices and interruptible loads may be complex, we do not believe that it is overly so. Further, we believe that the ERO, through its Reliability Standards development process can develop innovative solutions to the Commission’s concern. We also note that EEI is concerned about such testing at times of peak load. We clarify that we are not requiring the testing to be conducted at peak load conditions. Consequently, we reject the proposals of EEI, FirstEnergy and International Transmission to discard the requirement for reporting of the accuracy, error and bias of controllable load forecasts.

Consideration of Directive The SDT developed Requirement R1 of the proposed standard MOD-031-1 Demand Data Reporting. The requirement now states that an entity must provide an explanation of how the assumptions and methods for future forecasts were adjusted (Requirement R1 part 1.7.4).

Para 1277 We direct the ERO to include APPA’s proposal in the Reliability Standards development process to add a new requirement to MOD-019-0 that would oblige resource planners to analyze differences between actual and forecasted demands for the five years of actual controllable load and identify what corrective actions should be taken to improve controllable load forecasting for the 10-year planning horizon.

Consideration of Directive The informal ad hoc group developed Requirement R1 of the proposed standard MOD-031-1 Demand Data Reporting. The requirement now states that an entity must provide an explanation of how the assumptions and methods for future forecasts were adjusted (Requirement R1 part 1.7.4).

Para 1298 We agree with FirstEnergy and SMA that standardization of principles on reporting and validating DSM program information will provide consistent and uniform evaluation of demand response to facilitate system operator confidence in relying on such resources, which will further increase accuracy of transmission system reliability assessment and



consequently enhance overall reliability. We direct the ERO to modify this Reliability Standard to allow resource planners to analyze the causes of differences between actual and forecasted demands, and to identify any corrective actions that should be taken to improve forecasted demand responses for future forecasts. Therefore, we adopt the NOPR proposal and direct the ERO to modify MOD-021-0 by adding a requirement for standardization of principles on reporting and validating DSM program information.

Consideration of Directive The informal ad hoc group developed Requirement R1 of the proposed standard MOD-031-1 Demand Data Reporting. The requirement now states that an entity must provide an explanation of how DSM is forecasted and adjusted for errors (Requirement R1 part 1.7.3).

Conclusion


Conclusion

In developing the MOD C initiative, the informal ad hoc group and entities that participated in informal development discussed the key reliability impacts of the existing MOD C NERC Reliability Standards. The group identified and discussed issues at varying lengths early in the process and decided to consolidate the existing five standards into one pro forma standard. The approach is intended to maintain NERC’s focus on developing and retaining requirements that support the reliable operation of the Bulk Power System. This white paper provides a record of how the ad hoc group and industry participants in the informal development decided to address the outstanding directives from FERC Order 693, along with the other components of the results-based standards, such as a risk-based and performance-based standard, along with incorporating the Paragraph 81 initiative.


Appendix A: Entity Participants

The below entities represent a nonexhaustive list of entities that had personnel that participated in the MOD-C informal development effort in some manner, which may include one of the following: direct participation on the ad hoc group, inclusion on the wider distribution (the “plus”) list, attendance at workshops or other technical discussions, or by providing feedback to the group through a variety of methods (e.g., email, phone calls, etc.). Additionally, though not listed here, announcements were distributed to wider NERC distribution lists to provide the opportunity for entities that were not actively participating to join the effort.

Table 1: Entity Participation in MOD C Informal Development

Austin Energy Hydro Quebec MISO PG&E PSEG

American Transmission Co.

MEAG Power NI Source PJM XCEL Energy

CenterPoint Energy

Flathead Coop FERC PSEG MidAmerican

ERCOT

Regional Entities

FRCC

MRO

Puget Sound

NPCC

RFC

SERC

SPP

TRE

WECC

Table 2: Presentations and Events

NERC News NERC Standards and Compliance Workshop

NERC Operating Committee Reliability Assessment Subcommittee

NERC Planning Committee Reliability Assessment Data Working Group

NERC Standards Committee MRO PC/OC

Proposed Timeline for the Project 2010-04 Standard Drafting Team

Anticipated Date Location Event

July 2013 - SC Authorizes SAR and Pro Forma Standard for Posting

July 2013 - Conduct Nominations for Project 2010-04 SDT

July 2013 - Post SAR and Pro Forma Standard for 45-Day Informal

Comment Period



September 2013 TBD MOD C Standard Drafting Team Face to Face Meeting to

Respond to Initial Comments and Revise as Necessary

September 2013 - Conduct Recirculation Ballot



Authorities


July 18, 2013

PER Informal Development Project Requested Action

1. Authorize the concurrent posting of the PER Standards Authorization Request (SAR) for a 45-day informal comment period (given it is addressing FERC directives) along with the revised PER reliability standard (proposed PER-005-2), VRFs/VSLs, and associated implementation plan for a 45-day comment period with a ballot pool formed during the first 30 days of the comment period, and a ballot and non-binding poll conducted during the last ten days of that comment period; and

2. Approve the posting for a 10-day solicitation for nominations for Standard Drafting Team members for PER’s formal development.

The PER project is assigned the project number 2010-01. Additionally, a redline of the revised standard has not been developed due to the significant amount of changes. The rationale boxes provided in the standard explains the changes. Background On March 16, 2007 the Federal Energy Regulatory Commission (FERC) issued Order No. 693, Mandatory Reliability Standards for the Bulk-Power System and on November 18, 2010 FERC issued Order No. 742, System Personnel Training Reliability Standards. Five outstanding directives remain from those two orders (3 from Order No. 693 and 2 from Order No. 742), which are explained in detail in the PER White Paper contained in the SAR package. The informal consensus building for PER began in February 2013. Specifically, the ad hoc group engaged stakeholders on how best to address the FERC directives, paragraph 81 candidates and results-based approaches (see page 4 of the PER White Paper regarding the paragraph 81 candidate). A discussion of the ad hoc group’s consensus building and collaborative activities are included in the PER White Paper (see SAR package). Based on stakeholder outreach, the PER ad hoc group has developed one revised proposed reliability standards (PER-005-2) that address the FERC directives and recommendations for improving PER-005-1, which included creating results-based requirements and considering paragraph 81 criteria to ensure that the standards proposals did not include requirements that meet those criteria. A further discussion of this topic is included in the SAR package (see page 4 of the “PER White Paper” document). The goal is to present the PER standard to the NERC Board of Trustees (Board) during its November 2013 meeting, and for the Board adopted PER Reliability Standard to be filed with the applicable regulatory authorities by the end of 2013. Standard Drafting Team The PER drafting team is proposed to consist of a maximum of 10 members. Since this project is a continuation of informal development, several drafting team members will be selected from members of the informal group and the remainder from industry. A confidential slate of candidates with recommendations for appointment will be provided following the public


July 18, 2013 solicitation. The purpose of this appointment/solicitation approach is to ensure a smooth transition from the informal to formal standards development process for PER, while also providing an opportunity for solicitation of new members to help provide a well-rounded perspective to moving PER forward. The public solicitation shall request that standard drafting team members have experience in one or more of the following areas: training and operations. In addition, team members with experience in compliance, legal, regulatory, and technical writing are desired. Previous drafting team experience is beneficial, but not a requirement. Quality Review A quality review was coordinated by NERC staff for the posting of the PER reliability standard, implementation plan, VRFs and VSLs, and other associated documents. Project Schedule The drafting team is expected to facilitate meeting the proposed schedule contained in the SAR package.

PER SAR Package Submittal to the NERC Standards Committee July 2013



PER Standards Committee Package - Contents Bookmark Description

Standards Authorization Request An informal development ad hoc group is presenting a pro forma standard that address five (5) outstanding FERC directives.

Pro Forma Standard The pro forma standard is the result of four (4) out of the five outstanding FERC directives. This pro forma standard is a revised PER-005-1.


Implementation Plan The implementation plan gives the overview of how the retirement of the existing standards will be tied to the effective date of the pro forma standard.

Mapping Document The mapping document correlates the requirements within the existing PER standards to the requirements within the pro forma.

Technical White Paper The purpose of this white paper is to provide background and technical rationale for the proposed revisions of the PER standard.




NERC welcomes suggestions to improve the reliability of the bulk power system through improved reliability standards. Please use this form to submit your request to propose a new or a revision to a NERC’s Reliability Standard.


Title of Proposed Standard: Operations Personnel Training



Name: Jordan Mallory

Organization: NERC



New Standard



Urgent Action

SAR Information


Resolve FERC directives, modify System Operator definition (project 2010-16), and to incorporate initiatives such as results-based, performance-based, Paragraph 81, etc.


[email protected]

mailto:[email protected]�

mailto:[email protected]�

Project 2010-01 Standards Authorization Request July 18, 2013 2

SAR Information


• Modify System Operator Definition (Project 2010-16)

• Define applicable entities to address outstanding FERC Directives from Order No. 693 and Order No. 742.

• Modify existing PER-005-1 requirements for additional applicable entities and personnel.

• Remove existing PER-005-1 R3 prescriptive 32 hours of emergency operations as it is covered under the Systematic Approach to Training and thus is repetitive. In Paragraph 81 of the March 15, 2012 Order (link), FERC provided an opportunity for the ERO to remove requirements that did little to protect to the BPS pursuant to specific criteria. The requirement for 32 hours of training meets the Paragraph 81 criteria for redundancy. It further is not a results-based requirement, as it is unnecessarily prescriptive.


This project will be addressing the following FERC directives. In addition, the project will be reviewing the present standard to eliminate in ambiguity within the standard.

1. This SAR is needed to address outstanding FERC Directives from Order No. 693 and Order No. 742. The following is a summary of the FERC Directives to the ERO:

Develop specific Requirements addressing the scope, content and duration appropriate for generator operator personnel. A new requirement R5 has been suggested as an addition to a revised PER-005-1 capturing Generator Operators Personnel at a centrally located dispatch center who receive direction from their Reliability Coordinator, Balancing Authority, Transmission Operator, or Transmission Owner and may develop specific dispatch instructions for plant operators under their control. Personnel at a centrally located dispatch center who relay dispatch instructions, without making any modifications, are excluded.

Include personnel who carry out outage coordination and assessments in accordance with IRO-004-1 and TOP-002-2 and determine SOLs and IROLs or operating nomograms in accordance with IRO-005-1 and TOP-004-0. A new requirement R4 has been suggested as an addition to a revised PER-005-1 capturing operation support and support staff personnel for training. The term Support Personnel has been created with a definition solely for the revised PER-005-1 standard.

Consider whether personnel responsible for ensuring that critical reliability applications of the EMS, such as state estimator, contingency analysis and alarm processing packages are available, up-to-date in terms of system data and produce useable results should be included in a mandatory training standard. (Technical Justification)

Consider the necessity of developing a similar implementation plan with respect to PER-005-1, Requirement R3.1. (simulation technology)

Develop a definition of “local transmission control center” for developing the training requirements for local transmission control center operator personnel. The group thought it would be a better path to define local transmission control center through extending the

http://www.ferc.gov/whats-new/comm-meet/2012/031512/E-3.pdf�


SAR Information

applicability to Transmission Owners versus creating a new term for the NERC Glossary. Transmission Owner in the PER standard is defined as “Personnel in a transmission control center who operate a portion of the Bulk Electric System at the direction of its Transmission Operator.” Transmission Owner has been added to all the requirements of the suggested revised PER-005-1 standard.

2. Revise definition of System Operator in glossary of terms to address industry concerns for clarity.

3. Implement Paragraph 81 by identifying Reliability Standards requirements that either: (a) provide little protection to the BPS; (b) are unnecessary or (c) are redundant.

Detailed Description (Provide a description of the proposed project with sufficient details for the standard drafting team to execute the SAR. Also provide a justification for the development or revision of the standard, including an assessment of the reliability and market interface impacts of implementing or not implementing the standard action.)

Detailed description of this project can be found in the Technical White Paper, of this SAR submittal package.



Regional Reliability Organization

Conducts the regional activities related to planning and operations, and coordinates activities of Responsible Entities to secure the reliability of the Bulk Electric System within the region and adjacent regions.

Reliability Coordinator Responsible for the real-time operating reliability of its Reliability Coordinator Area in coordination with its neighboring Reliability Coordinator’s wide area view.

Balancing Authority Integrates resource plans ahead of time, and maintains load-interchange-resource balance within a Balancing Authority Area and supports Interconnection frequency in real time.

Interchange Authority Ensures communication of interchange transactions for reliability evaluation purposes and coordinates implementation of valid and balanced interchange schedules between Balancing Authority Areas.




Resource Planner Develops a >one year plan for the resource adequacy of its specific loads within a Planning Coordinator area.

Transmission Planner Develops a >one year plan for the reliability of the interconnected Bulk Electric System within its portion of the Planning Coordinator area.

Transmission Service Provider

Administers the transmission tariff and provides transmission services under applicable transmission service agreements (e.g., the pro forma tariff).


Transmission Operator

Ensures the real-time operating reliability of the transmission assets within a Transmission Operator Area.




Purchasing-Selling Entity

Purchases or sells energy, capacity, and necessary reliability-related services as required.


Load-Serving Entity Secures energy and transmission service (and reliability-related services) to serve the End-use Customer.



1. Interconnected bulk power systems shall be planned and operated in a coordinated manner to perform reliably under normal and abnormal conditions as defined in the NERC Standards.

2. The frequency and voltage of interconnected bulk power systems shall be controlled within defined limits through the balancing of real and reactive power supply and demand.

3. Information necessary for the planning and operation of interconnected bulk power systems shall be made available to those entities responsible for planning and operating the systems



reliably.

4. Plans for emergency operation and system restoration of interconnected bulk power systems shall be developed, coordinated, maintained and implemented.

5. Facilities for communication, monitoring and control shall be provided, used and maintained for the reliability of interconnected bulk power systems.

6. Personnel responsible for planning and operating interconnected bulk power systems shall be trained, qualified, and have the responsibility and authority to implement actions.

7. The security of the interconnected bulk power systems shall be assessed, monitored and maintained on a wide area basis.


Does the proposed Standard comply with all of the following Market Interface Principles?

Enter

(yes/no)


Yes


Yes


Yes


Yes

Related Standards



Related SARs

SAR ID Explanation

Regional Variances

Region Explanation

ERCOT None

FRCC None

MRO None

NPCC None

RFC None

SERC None

SPP None

WECC None

PER-005-2 — Opera tions Pers onnel Tra in ing

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15-day Formal Comment Period with Parallel Ballot September 2013

Recirculation ballot October 2013



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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, these defined terms will be removed from the individual standard and added to the Glossary.

System Operator: An individual at a cControl cCenter (Balancing Authority, Transmission Operator, Generator Operator, Reliability Coordinator) whose responsibility it is to monitor and control that operates or directs the operation of the Bulk eElectric sSystem in rReal- time. The following terms are defined for use only within PER-005-2, and should remain with the standard upon approval rather than being moved to the NERC Glossary of Terms:

System Personnel: System Operators of a Reliability Coordinator, Transmission Operator or Balancing Authority, and the Transmission Owner personnel described in the Applicability Section of this standard.

Support Personnel: Individuals who carry out outage coordination and assessments, or determine SOLs, IROLs or operating nomograms1

1 Nomograms are used in the WECC region to describe element operating limits.

for Real-time operations.


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When this standard has received ballot approval, the text boxes will be moved to the Application Guidelines Section of the Standard. A. Introduction

1. Title: Operations Personnel Training

2. Number: PER-005-2

3. Purpose: To ensure that personnel performing or supporting Real-time, reliability-related tasks on the Bulk Electric System are competent to perform those tasks.

4. Applicability:


4.1.1 Reliability Coordinator

4.1.2 Balancing Authority

4.1.3 Transmission Operator

4.1.4 Transmission Owner that has:

4.1.4.1 Personnel in a transmission control center who operate a portion of the Bulk Electric System at the direction of its Transmission Operator.

4.1.5 Generator Operator that has:

4.1.5.1 Personnel at a centrally located dispatch center who receive direction from their Reliability Coordinator, Balancing Authority, Transmission Operator, or Transmission Owner and may develop specific dispatch instructions for plant operators under their control.

4.1.5.1.1 Personnel at a centrally located dispatch center who relay dispatch instructions, without making any modifications, are excluded.

Rationale for Transmission Owner: Extending the applicability to Transmission Owners is necessary to address the FERC directive that the ERO develop formal training requirements for local transmission control center operator personnel. In Order No. 742 at P 62, the Commission clarified its understanding that local control center personnel exercise control over a significant portion of the Bulk-Power System under the supervision of the personnel of the registered transmission operator. The supervision may take the form of directive specific step-by-step instructions and at other times may take the form of the implementation of predefined operating procedures. In all cases, the Commission continued, the local transmission control center personnel must understand what they are required to do in the performance of their duties to perform them effectively on a timely basis. Thus, omitting such local transmission control center personnel from the PER-005-1 training requirements creates a reliability gap.

Rationale for Generator Operator: Extending the applicability to Generator Operators at a centrally located dispatch center is necessary to address the FERC directive that the ERO develop specific requirements addressing the scope, content and duration appropriate for generator operator personnel. The Commission explains in Order No. 693 at P 1359 that although a generator operator typically receives instructions from a balancing authority, it is essential that generator operator personnel have appropriate training to understand those instructions, particularly in an emergency situation in which instructions may be succinct and require immediate action. Order No. 742 further clarified that the directive applies to generator operator personnel at a centrally-located dispatch center who receive direction and then develop specific dispatch instructions for plant operators under their control. Plant operators located at the generator plant site are not required to be trained in PER-005-2.


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5. Effective Date: 5.1. Requirement R1, Requirement R2, Requirement R3 part 3.1, Requirement R4

and Requirement R5 shall become effective the first day of the first calendar quarter that is 24 months beyond the date that this standard is approved by applicable regulatory authorities, or in those jurisdictions where regulatory approval is not required, Requirement R1, Requirement R2, Requirement R3 part 3.1, Requirement R4 and Requirement R5 become effective the first day of the first calendar quarter that is 24 months beyond the date this standard is approved by the NERC Board of Trustees’, or as otherwise made pursuant to the laws applicable to such ERO governmental authorities.

5.2. Requirement R3, with the exclusion of part 3.1, shall become effective the first day of the first calendar quarter beyond the date that this standard is approved by applicable regulatory authorities, or in those jurisdictions where regulatory approval is not required, Requirement R3 becomes effective the first day of the first calendar quarter beyond the date this standard is approved by the NERC Board of Trustees’, or as otherwise made pursuant to the laws applicable to such ERO governmental authorities.


R1. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall use a systematic approach to training (SAT) to develop and implement a training program for its System Personnel as follows: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

1.1. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall create a list of BES company-specific Real-time reliability-related tasks.

1.1.1. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall review and update its list of tasks identified in part 1.1 each calendar year.

1.2. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall design and develop training materials based on the task list created in part 1.1 and part 1.1.1.

Rationale for changes to requirements in the PER Standard related to Transmission Owners and Calendar Year: • Transmission Owners personnel at local transmission control centers have been added to the PER standard and

are subject to all the Requirements of PER-005-2. The reason for adding Transmission Owners is to address Order No. 693 and Order No. 742 FERC directives to include local transmission control center operator personnel.

• To address industry input, the term annual has been changed to each calendar year. • PER-005-2 provides a requirement for training, but does not create a requirement for certification.


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1.3. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall deliver the training established in part 1.2 to System Personnel.

1.4. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall conduct an evaluation each calendar year of the training program established in Requirement R1 to identify any needed changes to the training program and shall implement the changes identified.

M1. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall review and update its list of tasks identified in part 1.1 each calendar year.

M1.1 Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall have available for inspection its company-specific Real-time reliability-related task list, with the date of the last update, as specified in Requirement R1 parts 1.1 and 1.1.1.

M1.2 Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall have available for inspection training materials, as specified in Requirement R1 part 1.2.

M1.3 Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall have available for inspection System Personnel training records showing the names of the people trained, the title of the training delivered and the dates of delivery to show that it delivered the training, as specified in Requirement R1 part 1.3.

M1.4 Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall have available for inspection evidence (such as instructor observations, trainee feedback, supervisor feedback, course evaluations, learning assessments, or internal audit results) that it performed an annual training program evaluation, as specified in Requirement R1 part 1.4.

R2. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall verify, at least once, the capabilities of its System Personnel identified to perform each assigned task in Requirement R1 parts 1.1 and 1.1.1. [Violation Risk Factor: High] [Time Horizon: Long-term Planning ]

2.1. Within six months of a modification or addition of Bulk Electric System company-specific Real-time reliability-related tasks, each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall verify the capabilities of each of its System Personnel to perform the new or modified tasks identified in Requirement R1 part 1.1.1.

Rationale for changes to R2: A change from System Operator to System Personnel is used to capture Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner in one term versus spelling each term out a second time in the requirement.


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M2. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall have available for inspection evidence to show that it verified the capabilities of each of the System Personnel identified to perform each assigned task in Requirement R1 parts 1.1 and 1.1.1, as specified in Requirement R2. This evidence can be documents such as training records showing successful completion of tasks with the employee name and date; supervisor check sheets showing the employee name, date, and task completed; or the results of learning assessments.

R3. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner that has operational authority or control over Facilities with established IROLs or has established operating guides or protection systems to mitigate IROL violations shall provide its System Personnel with emergency operations training using simulation technology such as a simulator, virtual technology, or other technology that replicates the operational behavior of the Bulk Electric System. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

3.1. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner that gains operational authority or control over a Facility with an established IROL or establishes operating guides or protection systems to mitigate IROL violations shall comply with Requirement R3 within 6 months of gaining that authority, control or establishing such operating guides or protection systems.

M3. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall have available for inspection training records that provide evidence that System Personnel completed training that includes the use of simulation technology, as specified in Requirement R3.

M3.1 Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall have available for inspection training records that provide evidence that System Personnel completed training that included the use of simulation technology, as specified in Requirement R3, within 6 months of gaining that authority, control or establishing such operating guides or protection systems.

Rationale for changes to R3: The 32 hours of Emergency Operations training has been removed since this training should be covered as part of the systematic approach to training process in Requirement R1. The 32 hours is inherent to the systematic approach to training process and a legacy to the 2003 blackout. The removal of 32 hours is also considered to be a paragraph 81 concept due to it being redundant to the systematic approach to training process. Requirement R3.1 also covers the FERC directive for the creation of an implementation plan for simulation technology.


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R4. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall establish and implement training for Support Personnel specific to those Real-time reliability-related tasks identified by the entity pursuant to Requirement R1 part 1.1 and part 1.1.1 that relate to the Support Personnel’s job function. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

M4. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall have available for inspection training materials and training records that provide evidence that Support Personnel completed training. This evidence can be documents such as training records showing successful completion of training with the employee name and date.

R5. Each Generator Operator shall use a systematic approach to training to establish and implement training for its personnel described in applicability section 4.1.5. The training shall also include topics identified as follows: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning ]

5.1. Each Generator Operator shall coordinate with its Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner to identify training topics that address the impact of the decisions and actions of a Generator Operator’s personnel as it pertains to the reliability of the Bulk Electric System during normal and emergency operations.

5.1.1. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall provide input as requested by the Generator Operator.

M5. Each Generator Operator shall have available for inspection training materials and training records that provide evidence that its applicable personnel completed

Rationale for R4: This is a new requirement applicable to Support Personnel as defined above in the definition section. In FERC Order No. 742, the Commission noted that NERC, in developing Reliability Standard PER-005-1, did not comply with the directive in FERC Order No. 693 to expand the applicability of training requirements to include operations planning and operation support staff who carry out outage planning and assessments and those who develop System Operating Limits (SOL), Interconnection Reliability Operating Limits (IROL), or operating nomograms for Real-time operations. This requirement does not require that entities create a new, comprehensive systematic approach to training (SAT) process for training support personnel. Rather, the requirements contemplate that entities will look to the SAT process already developed for System Operators. The entity can use the list created from requirement R1 and select the reliability-related tasks that support personnel conduct and therefore should be trained on.

Rationale for R5: This is a new requirement applicable to Generator Operators described in the applicability section. In FERC Order No. 742, the Commission noted that in developing proposed Reliability Standard PER-005-1, NERC did not comply with the directive in FERC Order No. 693 to expand the applicability of training requirements to include generator operators centrally-located at a generation control center with a direct impact on the reliable operation of the Bulk-Power System. The Commission acknowledged that the training for GOPs need not be as extensive as the training for TOPs and BAs. FERC also stated that the systematic approach to training methodology is flexible enough to build on existing training programs by validating and supplementing the existing training content, where necessary, using systematic methods. It is important that the relevant generator operator personnel receive the necessary training. This requirement does not necessitate an SAT process that is as comprehensive as that used for TOPs, RCs and BAs. R5 also acknowledges that in order to provide the necessary training applicable to GOPs, GOPS will need to coordinate with their RC, BA, TOP and TO to understand the training topics that each GOP should be trained on.


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training. This evidence can be documents such as training records showing successful completion of training with the employee name and date.

M5.1 Each Generator Operator shall have available for inspection evidence, such as an email or attestation that it coordinated with the Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner in establishing the training requirements.

M5.1.1 Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall have available for inspection evidence, such as an email or attestation, that it provided input to the Generator Operator.

C. Compliance 1. Compliance Monitoring Process


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.


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

Each Reliability Coordinator, Balancing Authority, Transmission Operator Transmission Owner, and Generator Operator shall keep data or evidence to show compliance for three years or since its last compliance audit, whichever time frame is the greatest, unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation.

If a Reliability Coordinator, Balancing Authority, Transmission Operator Transmission Owner, or Generator Operator is found non-compliant, it shall keep information related to the non-compliance until found compliant.

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


As defined in the NERC Rules of Procedure, “Compliance Monitoring and Assessment Processes” refers to the identification of the processes that will be


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used to evaluate data or information for the purpose of assessing performance or outcomes with the associated reliability standard.


None

D. Regional Variances None.

E. Interpretations None.

F. Associated Documents None.


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Medium None The Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner, failed to provide evidence that it updated its company-specific Real-time reliability-related task list to identify new or modified tasks each calendar year (1.1.2)

OR

The Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner, failed to provide evidence of evaluating its training program each calendar year to identify needed changes to its training program(s). (1.4)

The Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner failed to design and develop training materials based on the task lists. (1.2)

The Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner failed to prepare a task list (1.1 or 1.1.1.)

OR

The Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner failed to deliver training based on the task lists. (1.3)


High None The Reliability Coordinator, Balancing Authority, Transmission Operator, and

The Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner

The Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner verified less


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Transmission Owner verified at least 90% but less than 100% of its System Personnel capabilities to perform each assigned task from its tasks list. (R2)

verified at least 70% but less than 90% of its System Personnel capabilities to perform each assigned task from its task lists (R2)

OR

The Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner failed to verify its System Personnel capabilities to perform each new or modified task within six months of making a modification to its task list of the tasks in Real-time. (2.1)

than 70% of its System Personnel capabilities to perform each assigned task from its task lists. (R2)


Medium None None None The Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner did not provide its System Personnel with any form of simulation technology training (R3)

OR

The Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner did not verify its System Personnel capabilities to perform each new or modified task within six months of making a modification to its task list. (R3.1)


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Medium None None None The Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner failed to establish training for its Support Personnel (R4)

OR

The Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner failed to implement training for its Support Personnel. (R4)


Medium None None The Generator Operator failed to use a systematic approach to training to establish training requirements as defined in Requirement R5.

The Generator Operator failed to coordinate with its Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner to identify training topics as defined in Requirement R5 part 5.1

OR

The Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner failed to provide the requested input as defined in Requirement R5 part 5.1.1.

OR

The GOP failed to implement the training as defined in Requirement R5.


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Guidelines and Technical Basis Requirement R1:

Any systematic approach to training will: 1) determine the skills and knowledge needed to perform tasks, 2) determine what training is needed to achieve those skills and knowledge, 3) determine how to assess the acquisition of those skills and knowledge by the learner, 4) should determine if the learner can perform the task(s) acceptably in either a training or on-the-job environment, 5) determine if the training is effective, and make adjustments as necessary.

Reference #1: Determining Task Performance Requirements The purpose of this reference is to provide guidance in writing a performance standard that describes the desired outcome of a task. A standard for acceptable performance should be in either measurable or observable terms. Clear standards of performance are necessary for an individual to know when he or she has completed the task and to ensure agreement between employees and their supervisors on the objective of a task. Performance standards answer the following questions:

How timely must the task be performed?

Or

How accurately must the task be performed?

Or

With what quality must it be performed?

Or

What response from the customer must be accomplished? When a performance standard is quantifiable, successful performance is more easily demonstrated. For example, in the following task statement, the criteria for successful performance is to return system loading to within normal operating limits, which is a number that can be easily verified.

Given a System Operating Limit violation on the transmission system, implement the correct procedure for the circumstances to mitigate loading to within normal operating limits.

Even when the outcome of a task cannot be measured as a number, it may still be observable. The next example contains performance criteria that is qualitative in nature, that is, it can be verified as either correct or not, but does not involve a numerical result.

Given a tag submitted for scheduling, ensure that all transmission rights are assigned to the tag per the company Tariff and in compliance with NERC and NAESB standards.

Reference #2: Systematic Approach to Training References: The following list of hyperlinks identifies references for the NERC Standard PER-005 to assist with the application of a systematic approach to training:


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(1) DOE-HDBK-1078-94, A Systematic Approach to Training http://www.hss.energy.gov/NuclearSafety/techstds/standard/hdbk1078/hdbk1078.pdf

(2) DOE-HDBK-1074-95, January 1995, Alternative Systematic Approaches to Training, U.S. Department of Energy, Washington, D.C. 20585 FSC 6910 http://www.hss.energy.gov/NuclearSafety/techstds/standard/hdbk1074/hdb1074.html

(3) ADDIE – 1975, Florida State University http://www.nwlink.com/~donclark/history_isd/addie.html

(4) DOE Standard - Table-Top Needs Analysis DOE-HDBK-1103-96 http://hss.energy.gov/NuclearSafety/techstds/standard/hdbk1103/hdbk1103.pdf

Requirement R2:

Requirement R3:

Requirement R4:

Requirement R5:

Compliance Operations Draft Reliability Standard Compliance Guidance for PER-005-2 July 1, 2013 Introduction The NERC Compliance department (Compliance) worked with the PER-005 informal ad hoc group (PER Group) in a review of pro forma standard PER-005-2. The purpose of the review is to discuss the requirements of the pro forma standard to obtain an understanding of its intended purpose and the evidence necessary to support compliance. The purpose of this document is to address specific questions posed by the PER Group and Compliance in order to aid in the drafting of the requirements and provide a level of understanding regarding evidentiary support necessary to demonstrate compliance. However, this document makes no assessment as to the enforceability of the standard. While all testing requires levels of auditor judgment, participating in these reviews allows Compliance to develop training and approaches to support a high level of consistency in audits conducted by the Regional Entities. The following questions and answers are intended to both assist the PER Group in further refining the standard and to serve as a resource in the development of training for auditors. PER-005-2 Questions Question 1 For Requirement 1, what criteria would an auditor use to determine if a registered entity uses a systematic (SAT) approach to develop training? Compliance Response to Question 1 Without a definition of, or reference to, a specific SAT, it would be difficult for auditors to assess an entity’s training development program because no benchmark is provided within the standard. Compliance recommends the PER Group consider referencing a specific SAT process for registered entities to follow in developing training. Question 2 Is an auditor to assess a registered entity based on a SAT for the support personnel referenced in requirement 4? Compliance Response to Question 2 No, since the requirement does not specify use of a SAT, then Compliance will not require training be developed based on a SAT for requirement 4. Question 3 Since requirement 5 does not include the same sub-requirements as requirement 1 to define a SAT, do entities have to adhere to the requirement 1 sub-requirements for requirement 5?

Draft Reliability Standard Compliance Guidance for PER-005-2 July 1, 2013 2

Compliance Response to Question 3 As with requirement 1, without a definition of, or reference to, a specific SAT, it would be difficult for auditors to assess an entity’s training development program because no benchmark is provided within the standard. Compliance recommends the PER Group consider referencing a specific SAT process for registered entities to follow in developing training. Compliance Operations also notes that requirement 5 does not include the sub-requirements found in requirement 1 and is noting the inconsistency. Conclusion In general, Compliance finds this pro forma standard provides a reasonable level of guidance for Compliance auditors to conduct audits in a consistent manner. The standard establishes timelines, data requirements, and ownership of specific actions. In general, the standard would provide reasonable guidance to develop training to enable Compliance auditors to execute their reviews. Compliance does recommend the PER Group address the issues noted in the previous section of this document related to the standard.

Following final approval of the Reliability Standard, Compliance will develop the final Reliability Standards Auditor Worksheet (RSAW) and associated training. Attachment A represents the version of the pro forma standard requirements referenced in this document.

Attachment A

Requirements and Measures R1. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission

Owner shall use a systematic approach to training (SAT) to develop and implement a training program for its System Personnel as follows [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

1.1. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall review and update its list of tasks identified in part 1.1 each calendar year.

1.1.1. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall review and update its list of tasks identified in part 1.1 each calendar year.

1.2. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall design and develop training materials based on the task list created in part 1.1 and part 1.1.1.


1.4. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall conduct an evaluation each calendar year of the training program established in Requirement R1, to identify any needed changes to the training program and shall implement the changes identified.

M1. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall

M1.1 Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall have available for inspection its company-specific Real-time reliability-related task list, with the date of the last update, as specified in Requirement R1 parts 1.1 and 1.1.1.

M1.2 Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall have available for inspection training materials, as specified in Requirement R1 part 1.2.

M1.3 Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall have available for inspection System Personnel training records showing the names of the people trained, the title of the training delivered and the dates of delivery to show that it delivered the training, as specified in Requirement R1 part 1.3.

M1.4 Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall have available for inspection evidence (such as instructor


observations, trainee feedback, supervisor feedback, course evaluations, learning assessments, or internal audit results) that it performed an annual training program evaluation, as specified in Requirement R1 part 1.4.

R2. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall verify at least once, the capabilities of its System Personnel identified to perform each assigned task in Requirement R1 parts 1.1 and 1.1.1. [Violation Risk Factor: High] [Time Horizon: Long-term Planning ]


M2. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall have available for inspection evidence to show that it verified the capabilities of each of the System Personnel identified to perform each assigned task in Requirement R1 parts 1.1 and 1.1.1, as specified in Requirement R2. This evidence can be documents such as training records showing successful completion of tasks with the employee name and date; supervisor check sheets showing the employee name, date, and task completed; or the results of learning assessments.

R3. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner that has operational authority or control over Facilities with established IROLs or has established operating guides or protection systems to mitigate IROL violations shall provide its System Personnel with emergency operations training using simulation technology such as a simulator, virtual technology, or other technology that replicates the operational behavior of the BES. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]


M3. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall have available for inspection training records that provide evidence that System Personnel completed training that includes the use of simulation technology, as specified in Requirement R3.

M3.1 Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall have available for inspection training records that provide evidence that System Personnel completed training that included the use of simulation


technology, as specified in Requirement R3, within 6 months of gaining that authority, control or establishing such operating guides or protection systems.

R4. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall establish and implement training for Support Personnel specific to those Real-time reliability-related tasks identified by the entity pursuant to Requirement R1 part 1.1 and part 1.1.1 that relate to the Support Personnel’s job function. [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]

M4. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall have available for inspection training materials and training records that provide evidence that Support Personnel completed training. This evidence can be documents such as training records showing successful completion of training with the employee name and date.

R5. Each Generator Operator shall use a systematic approach to training to establish and implement training for its personnel described in applicability section 4.1.5 as follows: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning ]

5.1. Each Generator Operator shall coordinate with its Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner to identify training topics that address the impact of the decisions and actions of a GOP’s personnel as it pertains to the reliability of the Bulk Electric System during normal and emergency operations.

5.1.1. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall provide input as requested by the Generator Operator.

M5. Each Generator Operator shall have available for inspection training materials and training records that provide evidence that its applicable personnel completed training. This evidence can be documents such as training records showing successful completion of training with the employee name and date.

M5.1 Each Generator Operator GOP shall have available for inspection evidence, such as an email or attestation, that it coordinated with the RC, BA, TOP, and TO in establishing the training requirements.

M5.1.1 Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall have available for inspection evidence, such as an email or attestation, that it provided input to the Generator Operator.

Project 2010-01 Operations Personnel Training PER-005-2 Mapping Document

PER-005-1 Mapping to Proposed NERC Reliability Standard PER-005-2

Standard PER-005-1 NERC Board Approved

Transitions to the below Requirement in New Standard or Other

Action

Proposed Standard PER-005-2

R1. Reliability Coordinator, Balancing Authority and Transmission Operator shall use a systematic approach to training to establish a training program for the BES company-specific reliability-related tasks performed by its System Operators and shall implement the program. 1.1. Each Reliability Coordinator, Balancing

Authority and Transmission Operator shall create a list of BES company-specific reliability-related tasks performed by its System Operators. 1.1.1. Each Reliability Coordinator,

Balancing Authority and Transmission Operator shall update its list of BES company-specific reliability-related tasks performed by its System

Requirement R1 parts 1.1.1., 1.1.

R1. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall review and update its list of tasks identified in part 1.1 each calendar year.

1.1. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall review and update its list of tasks identified in part 1.1 each calendar year.

1.1.1. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall design and develop training materials based on the task list created in part 1.1 and part 1.1.1


1.3. Each Reliability Coordinator, Balancing Authority,

Project 2010-01 Real System Personnel Training Revisions July 18, 2013 2




Action


Operators each calendar year to identify new or modified tasks for inclusion in training.

1.2. Each Reliability Coordinator, Balancing Authority and Transmission Operator shall design and develop learning objectives and training materials based on the task list created in R1.1. 1.3. Each Reliability Coordinator, Balancing Authority and Transmission Operator shall deliver the training established in R1.2. 1.4. Each Reliability Coordinator, Balancing Authority and Transmission Operator shall conduct an annual evaluation of the training program established in R1, to identify any needed changes to the training program and shall implement the changes identified.

Transmission Operator, and Transmission Owner shall conduct an evaluation each calendar year of the training program established in Requirement R1, to identify any needed changes to the training program and shall implement the changes identified.

R2. Each Reliability Coordinator, Balancing Authority and Transmission Operator shall verify each of its System Operator’s capabilities to perform each assigned task identified in R1.1 at least one time.

Requirement R2

R2: Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall verify at least once, the capabilities of its System Personnel identified to perform each assigned task in Requirement R1





Action


2.1. Within six months of a modification of the BES company-specific reliability-related tasks, each Reliability Coordinator, Balancing Authority and Transmission Operator shall verify each of its System Operator’s capabilities to perform the new or modified tasks.

parts 1.1 and 1.1.1.


R3. At least every 12 months each Reliability Coordinator, Balancing Authority and Transmission Operator shall provide each of its System Operators with at least 32 hours of emergency operations training applicable to its organization that reflects emergency operations topics, which includes system restoration using drills, exercises or other training required to maintain qualified personnel.

This Requirement has been updated with deleting R3 and moving 3.1 from the approved standard to be the new R3. Part 3.1 in the proposed standard it addresses the implementation of simulation technology.

R3. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner that has operational authority or control over Facilities with established IROLs or has established operating guides or protection systems to mitigate IROL violations shall provide its System Personnel with emergency operations training using simulation technology such as a simulator, virtual technology, or other technology that replicates the operational behavior of the Bulk Electric System.





Action


3.1. Each Reliability Coordinator, Balancing Authority and Transmission Operator that has operational authority or control over Facilities with established IROLs or has established operating guides or protection systems to mitigate IROL violations shall provide each System Operator with emergency operations training using simulation technology such as a simulator, virtual technology, or other technology that replicates the operational behavior of the BES during normal and emergency conditions.


This requirement is new to PER-005-2.

R4. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall establish and implement training for Support Personnel specific to those Real-time reliability-related tasks identified by the entity pursuant to Requirement R1 part 1.1 and part 1.1.1 that relate to the Support Personnel’s job function.

This requirement is new to PER-005-2.

R5. Each Generator Operator shall use a systematic approach to training to establish and implement training for its personnel described in applicability section 4.1.5 as follows: [Violation Risk Factor: Medium] [Time Horizon:





Action


Long-term Planning ]

5.1 Each Generator Operator shall coordinate with its Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner to identify training topics that address the impact of the decisions and actions of a Generator Operator’s personnel as it pertains to the reliability of the Bulk Electric System during normal and emergency operations.

5.1.1.Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner shall provide input as requested by the Generator Operator.

Implementation Plan Project 2010-01 Operations Personnel Training

Implementation Plan for PER-005-2 – Operations Personnel Training Approvals Required PER-005-2 – Operations Personnel Training


Revisions to Glossary Terms The following definitions shall become effective when PER-005-2 becomes effective:

System Operator: An individual at a Control Center that operates or directs the operation of the Bulk Electric System in real-time.

The following terms are defined for use only within PER-005-2, and should remain with the standard upon approval rather than being moved to the NERC Glossary of Terms:

System Personnel: System Operators of a Reliability Coordinator, Transmission Operator or Balancing Authority, and the Transmission Owner personnel described in the Applicability Section of this standard.

Support Personnel: Individuals who carry out outage coordination and assessments, or determine SOLs, IROLs or operating nomograms for Real-time operations.

Applicable Entities

• Reliability Coordinator

• Balancing Authority

• Transmission Operator

• Transmission Owner that has personnel in a Transmission control center who operate a portion of the Bulk Electric System at the direction of its Transmission Operator

• Generator Operator that has personnel at a centrally located dispatch center who receive direction from their Reliability Coordinator, Balancing Authority, Transmission Operator, or Transmission Owner and may develop specific dispatch instructions for plant operators under their control.

Project 2010-01 – Operations Personnel Training July 18, 2013

2

Applicable Facilities None Conforming Changes to Other Standards None Effective Dates PER-005-2 shall become effective as follows:

• Requirement R1, Requirement R2, Requirement R3 part 3.1, Requirement R4 and Requirement R5 shall become effective the first day of the first calendar quarter that is 24 months beyond the date that this standard is approved by applicable regulatory authorities, or in those jurisdictions where regulatory approval is not required, Requirement R1, Requirement R2, Requirement R3 part 3.1, Requirement R4 and Requirement R5 become effective the first day of the first calendar quarter that is 24 months beyond the date this standard is approved by the NERC Board of Trustees’, or as otherwise made pursuant to the laws applicable to such ERO governmental authorities.

• Requirement R3, with the exclusion of part 3.1, shall become effective the first day of the first calendar quarter beyond the date that this standard is approved by applicable regulatory authorities, or in those jurisdictions where regulatory approval is not required, Requirement R3 becomes effective the first day of the first calendar quarter beyond the date this standard is approved by the NERC Board of Trustees’, or as otherwise made pursuant to the laws applicable to such ERO governmental authorities.

Justification The 24-month period for implementation of PER-005-2 will provide ample time for the applicable entities to make necessary modifications to existing or creation of new systematic approach to training programs for compliance.

Retirements PER-005-1 – System Personnel Training should be retired at midnight of the day immediately prior to the effective date of PER-005-2 in the particular jurisdiction in which the new standard is becoming effective.

Rationale for changes to requirements in the PER Standard related to Transmission Owners and Calendar Year: • Transmission Owners personnel at local transmission control centers have been added to the PER standard and

are subject to all the Requirements of PER-005-2. The reason for adding Transmission Owners is to address Order No. 693 and Order No. 742 FERC directives to include local transmission control center operator personnel.

• To address industry input, the term annual has been changed to each calendar year. • PER-005-2 provides a requirement for training, but does not create a requirement for certification.

Project 2010-01 – Operations Personnel Training July 18, 2013

3

Attachment 1 Approved Standards Incorporating the Term “System Operator”

EOP-005-2 — System Restoration from Blackstart Resources EOP-006-2 — System Restoration Coordination EOP-008-1 — Loss of Control Center Functionality IRO-002-3 — Reliability Coordination – Analysis Tools IRO-014-1 — Procedures, Processes, or Plans to Support Coordination between Reliability Coordinators MOD-008-1 — TRM Calculation Methodology MOD-020-0 — Providing Interruptible Demands and DCLM Data PER-003-1 — Operation Personnel Credentials PER-005-1 — System Personnel Training PRC-023 -2 — Transmission Relay Loadability

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PER-005 Standards White Paper July 18, 2013



NERC | PER-005 White Paper | June 6, 2013 2 of 22

Table of Contents

Table of Contents ......................................................................................................................................................................... 2

Executive Summary ..................................................................................................................................................................... 3

Purpose ........................................................................................................................................................................................ 5

History of the PER-005 Informal Development ........................................................................................................................... 6

Outstanding FERC Directives and Technical Discussions ............................................................................................................. 7

Applicability of the PER standard to GOP dispatchers ............................................................................................................. 7

FERC Order 693 ¶ 1360-1361, 1363 ........................................................................................................................................ 7

FERC Order 742 ¶ 83-84 .......................................................................................................................................................... 7


Technical Discussions ........................................................................................................................................................... 8

Applicability of the PER standard to Operations Planning and Operations Support Staff ....................................................... 9

FERC Order 693 ¶ 1366 ............................................................................................................................................................ 9

Consideration of Directive ................................................................................................................................................. 10

Technical Discussions ......................................................................................................................................................... 10

FERC Order 693 ¶ 1373 .......................................................................................................................................................... 10



New Simulation Technology Implementation Plan ............................................................................................................... 11

FERC Order 742 ¶ 24 .............................................................................................................................................................. 11



Applicability of the PER standard to Local Transmission Control Center .............................................................................. 11

FERC Order 742 ¶ 64 .............................................................................................................................................................. 11



Other Issues ........................................................................................................................................................................... 11

Inconsistent usage of each calendar year, annual, and at least every twelve months ..................................................... 11

Definitions .............................................................................................................................................................................. 11

System Operator Definition ............................................................................................................................................... 11

System Personnel Definition .............................................................................................................................................. 12

Conclusion ................................................................................................................................................................................. 13

Appendix A: Industry Arguments and FERC Responses ............................................................................................................. 14

Appendix B: Entity Participants ................................................................................................................................................. 22

Executive Summary


Executive Summary A Personnel, Performance, Training, and Qualifications (PER) ad hoc group was formed to work with industry stakeholders to address five outstanding Federal Energy Regulatory Commission (FERC) directives. The five outstanding FERC directives are as follows:

1. The Commission directs the Electric Reliability Organization (ERO) to develop specific requirements addressing the scope, content, and duration appropriate for Generator Operator (GOP) personnel (Order No. 693, P. 1363).

2. The Commission directs the ERO to develop a modification to PER-002-0 to require training of operations planning and operations support staff of Transmission Operators (TOPs) and Balancing Authorities (BAs) who have a direct impact on the reliable operation of the Bulk-Power System (BPS) (Order No. 693, P. 1372).

3. The Commission directs the ERO to consider personnel responsible for ensuring that critical reliability applications of the EMS, such as state estimator, contingency analysis and alarm processing packages, are available, up to date in terms of system data and produce useable results that can also have an impact on the reliable operation of the BPS (Order No. 693, P. 1373).

4. The Commission directs the ERO to consider the necessity of developing a similar implementation plan with respect to PER-005-1, Requirement R3.1 (Order No. 742, P. 24).

5. The Commission directs the ERO to develop through a separate reliability standards development project formal training requirements for local transmission control center operator personnel, and to develop a definition of “local transmission control center” in the standards development project (Order No. 742, P. 64).

The ERO is required to comply with FERC directives unless there is an equally effective and efficient method of addressing the reliability concern, or if there is evidence that the directive has been overcome by events or is no longer needed. These five directives were challenging due to the variance of industry opinion. The PER informal development project reviewed the FERC directives, conducted outreach to industry stakeholders, and developed the pro forma standard. There were differing opinions from industry; some stated that the directives should be complied with while others stated there was sufficient justification as to why the directives were no longer needed. Although persuasive, the majority of the arguments as to why the directives were no longer needed had been addressed by FERC in prior orders as outlined in Appendix A. The discussion for each of the above directives are summarized as follows. First, discussions were held regarding GOP dispatchers at a local control center. Through industry feedback, it became apparent that stakeholders needed a better understanding of the types of GOPs FERC was including in the directive. Initially it appeared that the directive would apply only to those GOPs that make independent decisions; however, FERC had addressed that narrow reading in FERC Order 693 P. 1359. The group’s final determination was that even though GOPs at a local control center receive direction from their BA or TOP, those that take direction and then develop dispatch instructions for their plant operators are the specific GOPs the FERC Orders are attempting to capture. Therefore, the pro forma standard expanded the applicability in PER-005 to include these specific types of GOPs. Second, the ad hoc group received strong feedback from industry that operations planning and operations support staff should not be included in the PER standard. Some of the reasons presented were: the System Operator is the one who impacts the Bulk Electric System (BES) and not the support personnel; support personnel do not make any Real-time decisions on BES operations; mandating training would distract training staff from the more critical functions of training System Operators; and this would create an administrative burden and would be too costly of a task on industry for the reliability protection it offers. Through further research it was determined that these were the same arguments previously presented and responded to by FERC in Orders 693 and 742 (see Appendix A). Therefore, as the informal development effort was not able to provide an argument that had not previously been rejected by FERC, the ad hoc group continued with the inclusion of support personnel in PER-005.

Executive Summary


The third major discussion was in regard to the directive for the ERO to consider including personnel responsible for ensuring that critical reliability applications of the EMS, such as state estimator, contingency analysus and alarm processing packages, are available, up-to-date in terms of system data and produce useable results can also have an impact on the reliable operation of the BPS. Similar to the previously described discussions, many of the arguments had been addressed by FERC, but there was new evidence in this area. The argument for not including EMS personnel in the training standard at this time is based on a report provided by the Event Analysis Subcommittee (EAS). The EAS worked with the NERC Event Analysis (EA) staff to review the events that have been cause-coded since October 2010. The database has over 263 events; 208 of them were cause-coded to allow for trending and cluster analysis. The EAS and NERC EA staff queried the 208 events and looked in particular for cause codes that pertain to human errors and training that were less than adequate. The query produced 44 events that had the possibility for human errors or training being a contributing factor in the event. An analysis of those 44 events indicated that only 10 had human error or training as a contributing factor. Six of those 10 events were related to the loss of EMS or SCADA. Out of the six events, only two were deemed to be a training issue. Therefore, based on the information, the EAS and PER ad hoc group do not believe it is necessary at this time to require EMS support personnel to receive the level of training required of a BA, Reliability Coordinator (RC), and TOP by NERC standard PER-005. Fourth, the ad hoc group and industry stakeholders agreed with the Commission on developing an implementation plan with respect to the simulation technology requirement. The ad hoc group determined that six months would suffice for an entity to become compliant with the simulation technology requirement in PER-005. No feedback has been received thus far from industry regarding this suggested change. Last, the group addressed the local transmission control center directive by expanding the PER-005 applicability section to Transmission Owners (TO) and creating a standard-only definition. The group defined “local transmission control center” in the standard as personnel in a transmission control center who operate a portion of the Bulk Electric System at the direction of its Transmission Operator. This term will not become a part of the NERC Glossary of Terms used in NERC Reliability Standards at this time. In summary, the PER ad hoc group created a pro forma standard (PER-005-2) extending the applicability to certain GOPs, support personnel, and TOs, excluding EMS support personnel. The 32-hour requirement has been removed as it is inherent to the systematic approach to training that training hours should be left up to each entity. The requirement for 32 hours of training meets the Paragraph 81 criteria for redundancy and was further not a results-based requirement and considered unnecessarily prescriptive. A new requirement R3.1 was created to develop the implementation of the simulation technology requirement. The pro forma standard was drafted to provide maximum flexibility to industry while addressing the reliability concerns in the FERC directives. Under the pro forma standard, each entity has the ability to identify its reliability-related tasks, determine which of its personnel conduct those tasks, and determine the appropriate training and level of training for each employee. The ad hoc group understood the concerns from industry regarding the systematic approach to training, and each requirement has been left up to the entity to decide which approach should be used.

Purpose


Purpose The purpose of the PER-005 white paper is to provide the issues, rationale, and support for the revisions to the PER-005 standard. This white paper provides an explanation of how each of the FERC directives was addressed, including the issues that were raised during informal development and the rationale for proceeding or not proceeding with each. This paper will also provide technical justification and support for the revisions to the standard. The contents in this paper will provide the standard drafting team with the basis for the pro forma standard so they can begin the formal standard development process.

History of the PER-005 Informal Development


History of the PER-005 Informal Development In February 2012, the North American Electric Reliability Corporation (NERC) Board of Trustees (Board) formed the Standards Process Input Group (SPIG) to address the widespread frustration with the duration of the standards development process.1 In May 2012, SPIG submitted a report to the NERC Board recommending improving both the timeliness and quality of the standards. The process manual changes were approved by the Board in February 2013.2 Since then, the Board issued a resolution requesting SPIG, the Members Representative Committee (MRC), NERC staff, and industry stakeholders to reform their standards development paradigm. Changes were integrated into the 2013–15 Reliability Standards Development Plan (RSDP) and Standards Committee (SC) Strategic Plan.3

The evolving standards process includes an informal development period in which NERC Standards developers work with an ad hoc group to gather information up front from industry regarding the FERC directives or other standards development project. There are three approaches to consider when addressing FERC directives: comply with the FERC directive, present an equally and effective alternative, or provide technical justification as to why the directive is no longer needed. A PER ad hoc group was formed in January of 2013 to work with industry stakeholders to address five outstanding FERC directives. The ad hoc group addressed each directive through informal development, with the goal of filing a revised standard with FERC by December 31, 2013. The PER ad hoc group held its first informal development meeting February 25–27, 2013, in Atlanta, Georgia. A small ad hoc group of industry subject matter experts (SMEs) representing RCs’, BAs’, GOPs’, TOPs’, and TOs’ participated in discussions about the FERC directives and possible resolutions to address them. The ad hoc group created the first draft of a pro forma standard to address each directive. The ad hoc group conducted conference calls, workshops, and, to reach additional industry participants, two webinars: a March 15 informational webinar and an April 4 industry feedback webinar requesting feedback from industry regarding the PER ad hoc group suggestions. Multiple conference calls were held with the ad hoc group to keep all members aware of feedback received. A second informal meeting was held April 22–23, 2013, at NERC’s Atlanta office. The meeting was a continuation of the efforts of the first meeting with the addition of discussion on the information received through the outreach efforts. The ad hoc group discussed issues raised by industry and revised the pro forma standard based on that information. The group presented the revised pro forma standard to industry at the May 31 industry feedback webinar and other conference calls. During the webinar, polling questions were presented to participants, and 147 out of 323 people participated in the polling. The purpose of this polling was to gauge industry’s support of the suggested PER-005 standard. The last informal development meeting was held June 20–21, 2013 to develop the materials necessary to move into the formal process. This will entail submitting a Standard Authorization Request (SAR), the pro forma standard, input to a reliability standards audit worksheet (RSAW), an implementation plan, a mapping document, and a technical white paper to the NERC Standards Committee (SC). A complete list of entities that participated during the informal development can be located in Appendix B.

1 May 9, 2012 NERC Board minutes: http://www.nerc.com/gov/bot/Agenda%20Minutes%20and%20Highlights%20DL/2012/BOT_050912m_complete.pdf 2 August 16, 2012 NERC Board minutes: http://www.nerc.com/gov/bot/Agenda%20Minutes%20and%20Highlights%20DL/2012/0-BOT08-12a-complete.pdf 3 2013–15 Reliability Standards Development Plan: http://www.nerc.com/pa/Stand/Standards%20Development%20Plan%20Library/2013-2015_RSDP_BOT_Approved_12-19-12.pdf

http://www.nerc.com/gov/bot/Agenda%20Minutes%20and%20Highlights%20DL/2012/BOT_050912m_complete.pdf�

http://www.nerc.com/gov/bot/Agenda%20Minutes%20and%20Highlights%20DL/2012/0-BOT08-12a-complete.pdf�

http://www.nerc.com/pa/Stand/Standards%20Development%20Plan%20Library/2013-2015_RSDP_BOT_Approved_12-19-12.pdf�

http://www.nerc.com/pa/Stand/Standards%20Development%20Plan%20Library/2013-2015_RSDP_BOT_Approved_12-19-12.pdf�

Outstanding FERC Directives and Technical Discussions


Outstanding FERC Directives and Technical Discussions There are five outstanding FERC directives from Order 6934 and Order 742.5

Each directive was discussed in detail during the informal development stage, and below are the summaries of the discussions.

Applicability of the PER Standard to GOP Dispatchers FERC Order 693 ¶ 1360-1361, 1363 P. 1360. We agree with FirstEnergy and others that some clarification is required regarding which generator operator personnel should be subject to formal training under the Reliability Standard. As noted above, a generator operator typically receives instructions from a balancing authority. Some generator operators are structured in such a way that they have a centrally-located dispatch center that receives direction and then develops specific dispatch instructions for plant operators under their control. For example, a balancing authority may direct a centrally-located dispatch center to deliver 300 MW to the grid, and the dispatch center would determine the best way to deliver that generation from its portfolio of units. In this type of structure, it is the personnel of the centrally located dispatch center that must receive formal training in accordance with the Reliability Standard. Plant operators located at the generator plant site also need to be trained but the responsibility for this training is outside the scope of the Reliability Standard. P. 1361. Other generator operators may be structured in such a way that the dispatch center and the single generation plant are at the same site. In this structure as well, some personnel will perform dispatch activities while others are designated as plant operators. Again, it is the dispatch personnel that must receive formal training in accordance with the Reliability Standard. Plant operators also need to be trained but the responsibility for this training is outside the scope of the Reliability Standard. P. 1363. Further, the Commission agrees with MidAmerican, SDG&E and others that the experience and knowledge required by transmission operators about Bulk-Power System operations goes well beyond what is needed by generation operators; therefore, training for generator operators need not be as extensive as that required for transmission operators. Accordingly, the training requirements developed by the ERO should be tailored in their scope, content and duration so as to be appropriate to generation operations personnel and the objective of promoting system reliability. Thus, in addition to modifying the Reliability Standard to identify generator operators as applicable entities, we direct the ERO to develop specific Requirements addressing the scope, content and duration appropriate for generator operator personnel. FERC Order 742 ¶ 83-84 P. 83. EPSA requests clarification of several statements in the NOPR regarding the Order No. 693 directive related to expanding the applicability of the system operator training Reliability Standard to include certain generator operators. First, EPSA expresses concern that the NOPR discussion broadly addresses generator operator personnel in a way that could be construed as subjecting all generator operator personnel, regardless of the disposition of the generating unit and how it fits into the grid and the topology of the grid, to the system operator training requirements. Therefore EPSA seeks clarification that the Commission did not intend for the NOPR to expand the Order No. 693 directives. We confirm that we have not modified the scope of applicability of the Order No. 693 directive regarding generator operator training. As described in Order No. 693, the directive applies to generator operator personnel at a centrally-located dispatch center who receive direction and then develop specific dispatch instructions for plant operators under their control. Those generator operator personnel must receive formal training of the nature provided to system operators under PER-005-1. As clarified in Order No. 693, this group of personnel would include a generator operator’s dispatch personnel where a single generator and dispatch center are located at the same site. P. 84. EPSA also seeks clarification regarding the statement in the NOPR that: “[I]n the event communication is lost, the generator operator personnel must have had sufficient training to take appropriate action to ensure reliability of the Bulk-Power System.” EPSA expresses concern that this statement suggests that if communication is lost with the grid operator, the generator operator must take unilateral action for which it requires training. EPSA notes that generator operators do not take such unilateral action nor do they have access to information to make such decisions. Therefore, EPSA asks the Id. Commission to make clear that while communication should be addressed in training requirements for centrally located generator operator dispatch employees, the Commission is not extending related responsibilities or training requirements to generator operator employees. We grant the requested clarification, and affirm that we are not modifying the Order No. 4 Mandatory Reliability Standards for the Bulk-Power System, 118 FERC ¶ 61,218, FERC Stats. & Regs. ¶ 31,242 (Order No. 693), order on reh’g, Mandatory Reliability Standards for the Bulk-Power System, 120 FERC ¶ 61,053 (Order No. 693-A) (2007). 5 FERC Order 742 PP 83-84



693 directive regarding training for certain generator operator dispatch personnel, nor are we expanding a generator operator’s responsibilities. Consideration of Directive The PER ad hoc group considered all options (such as complying with the FERC directive, presenting an equally and effective alternative, or providing technical justification as to why the directive is no longer needed) when addressing GOPs at a centrally located dispatcher center who receive direction and then develop specific dispatch instructions for plant operators under their control.6

The ad hoc group suggested a revised PER-005-1 standard that expands the applicability section to these specific GOPs, leaving it up to the entity to identify the reliability-related tasks its GOP personnel should be trained on. The group attempted to draw a bright line of GOPs that make independent decisions. Through subsequent discussions with FERC’s OER staff, the group learned that this bright line, per the FERC orders, would not address the FERC directive. It appears that the intent of the FERC order is for GOPs at a control center who receive direction from their BAs or TOPs to develop specific dispatch instructions (not just that make an independent decision) for their plant operator. These are the people who should be captured under the standard. The group considered and suggested a revised PER-005 that extends applicability to these specific GOPs. The standard language allows the entity to decide which systematic approach to training should be used when training GOPs and includes coordination on training topics with the entity’s RC, BA, TOP, and TO.

Technical Discussions Many technical discussions were held regarding increasing the applicability of the PER standard to GOP dispatchers. The feedback provided in the list below are the reasons provided by industry as to why this directive was no longer needed for GOP dispatchers.

• All decisions that GOPs make that impact the reliability of the BES must be approved by the BA, TOP, or RC. Even in the case of an emergency situation, the GOP will not make any decisions until approved by the BA, TOP, or RC. It was further explained that there are GOPs that do not develop dispatch instruction and simply take the information received from the BA, TOP, or RC and relayed information directly to the plant operator.

• FERC limited emergency shutdowns of generation to occur at the plant level, not the dispatch level; at this time, the FERC order does not require plant operators to be trained.

• The NERC Functional Model was stated many times as a reason to show that GOP dispatchers follow the direction of the BA or TOP. The NERC Functional Model for GOPs states that GOPs in Real time:

Provide Real-time operating information to the Transmission Operators and the required Balancing Authority.

Adjust real and reactive power as directed by the Balancing Authority and Transmission Operators.7

• When a GOP would be making decisions that impact reliability, they are also registered as the BA or TOP.

Entities that agreed with GOPs being added to the standard made the following comments:

• Consider including some criteria regarding various sizes of generation like in CIP Version 5.

• Consider creating a new standard addressing GOP dispatchers.

• PPL Electric Utilities Corp., Louisville Gas and Electric Co., and PPL Generation LLC stated that the TOP or BA should prepare the GOP training modules since the goal is to ensure that dispatchers do what the TOP or BA wants in emergency situations.

The arguments provided above constitutes the same arguments that FERC rejected in Order Nos 693 and 742 (see Appendix A).

6 FERC Order 742 P 83. 7 NERC functional model: http://www.nerc.com/pa/Stand/Resources/Documents/FunctionalModelTechnicalDocumentV5Clean2009Dec1.pdf

http://www.nerc.com/pa/Stand/Resources/Documents/FunctionalModelTechnicalDocumentV5Clean2009Dec1.pdf�



FERC Order 693 P. 1393 clearly states that GOP dispatchers need to be trained using the systematic approach to training methodology.

1393. Accordingly, the Commission approves Reliability Standard PER-002-0. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission directs the ERO to develop a modification to PER-002-0 through the Reliability Standards development process that: (1) identifies the expectations of the training for each job function; (2) develops training programs tailored to each job function with consideration of the individual training needs of the personnel; (3) expands the Applicability section to include (a) reliability coordinators, (b) local transmission control center operator personnel (as specified in the above discussion), (c) generator operators centrally-located at a generation control center with a direct impact on the reliable operation of the Bulk-Power System and (d) operations planning and operations support staff who carry out outage planning and assessments and those who develop SOLs, IROLs or operating nomograms for Real-time operations; (4) uses the Systematic Approach to Training (SAT) methodology in its development of new training programs and (5) includes the use of simulators by reliability coordinators, transmission operators and balancing authorities that have operational control over a significant portion of load and generation.8

The pro forma standard is written to require the use of a Systematic Approach to Training, but provides the entity the ability to determine the reliability-related tasks GOP dispatchers need to be trained on and the method of how the GOP dispatchers are trained. There were discussions regarding whether training for GOPs should be in a separate standard, however the current PER-005 is a systematic approach to training based standard and thus it is logical to include the GOP dispatchers within the current standard. Because the ad hoc group received the same feedback that was provided in FERC Order Nos. 693 and 742; the ad hoc group suggested expanding the applicability section in PER-005 to capture these certain GOP dispatchers using the systematic approach to training, which is left up to the entity.

Applicability of the PER Standard to Operations Planning and Operations Support Staff FERC Order 693 ¶ 1366 P. 1366. As mentioned above, the Commission proposed in the NOPR to direct the ERO to develop a modification to PER-002-0 to require training of operations planning and operations support staff of transmission operators and balancing authorities who have a direct impact on the reliable operation of the Bulk-Power System.9

FERC Order 742 ¶ 82 P. 82. Associated Electric expressed concern that the NOPR definition of the “operations planning and operations support staff” who should receive training pursuant to the Order No. 693 directive is “broad and will encompass operations planning and operation support staff who engage in tasks that do not directly affect the reliable operation of the bulk electric system.” The Commission clarifies that the scope of the Reliability Standard or modification to a Reliability Standard to address training for “operations planning and operations support staff” is limited by the qualifications stated in Order No. 693. Specifically, in Order No. 693, the Commission directed the ERO to develop a modification to PER-002-0 that extends applicability of the training requirements to the operations planning and operations support staff of transmission operators and balancing authorities. The Commission further clarified that such directive applies only to operations planning and operations support personnel who: “carry out outage coordination and assessments in accordance with Reliability Standards IRO-004-1 and TOP-002-2, and those who determine SOLs and IROLs or operating nomograms in accordance with Reliability Standards IRO-005-1 and TOP-004-0.” The NOPR did not expand or alter the scope of this directive as set forth in Order No. 693.10

8 FERC Order 693 P 1363.

9 FERC Order 693 P 1366. 10 FERC Order 742 P 82.



Consideration of Directive The PER ad hoc group held multiple discussions regarding the impact that operations planning and operations support staff have on the BES. The feedback received from industry regarding this topic was deemed to be the same arguments provided in the NOPR and rejected in FERC Orders 693 and 742 (see Appendix A). Therefore, the ad hoc group group revised PER-005-1 to incorporate operations planning and support personnel in the standard. Technical Discussions Industry provided the following information regarding operations planning and operations support staff about why training is not needed for support personnel:

• Training will provide no reliability benefit because of the administrative burden on entities and costly burden on industry with uncertain benefits.

• Training will provide no reliability impact because System Operators make the final decision, and support personnel do not make Real-time decisions.

• Operations planning and planning support staff is ambiguous and should be clarified.

• Entities appear to already train their support personnel; therefore, it should not be a mandatory requirement. Again, the feedback received was deemed to be the same arguments provided on FERC Orders 693 and 742; therefore, the ad hoc group revised PER-005-1 to incorporate operations planning and support personnel in the standard.

Applicability of the PER Standard to EMS Personnel FERC Order 693 ¶ 1373 1373. In addition, the Commission is aware that the personnel responsible for ensuring that critical reliability applications of the EMS, such as state estimator, contingency analysis and alarm processing packages, are available, up-to-date in terms of system data and produce useable results can also have an impact on the Reliable Operation of the Bulk-Power System. Because these employees’ impact on Reliable Operation is not as clear, we direct the ERO to consider, through the Reliability Standards development process, whether personnel that perform these additional functions should be included in mandatory training pursuant to PER-002-0.11

Consideration of Directive Through discussion with industry, the ad hoc group determined that the report provided by the Event Analysis Subcommittee (EAS) serves as rationale for why EMS personnel should not be included in the PER standard at this time. The technical discussion section below provides more in-depth information regarding this determination. Technical Discussions As background, in Orders 693 and 742, the Commission directed NERC to consider whether there is a need to include EMS personnel in the training standard. In contrast to the directive for GOPs and operations support personnel, FERC did not conclude that it was necessary to include EMS personnel in the standard; rather, it directed the ERO to consider EMS personnel inclusion. The ad hoc group discussed the issue with industry stakeholders and concluded that the data does not support a need to include EMS personnel in the standard at this time. Based on the information in the EMS report on cause-coded events, the EAS and PER ad hoc group do not believe it is necessary at this time to require EMS support personnel to receive the level of training required of a BA, Reliability Coordinator (RC), and TOP by NERC Reliability Standard PER-005. Lastly, the EMS events will continue to be monitored, and if EMS events begin to indicate that training is a root or contributing cause, NERC will readdress inclusion of EMS personnel to PER-005. A request will be submitted to the Operating Committee (OC) to produce an EMS guideline for training EMS personnel.

11 FERC Order 693 P 1373.



New Simulation Technology Implementation Plan FERC Order 742 ¶ 24 With respect to EEI’s comment regarding the effective date for entities that may become subject to the simulator training requirement in PER-005-1 R3.1, the Commission believes that this issue should be considered by the ERO. We note that, with respect to the Critical Infrastructure Protection (CIP) Reliability Standards, NERC has developed a separate implementation plan that essentially gives responsible entities some lead time before newly acquired assets must be in compliance with the effective CIP Reliability Standards. We direct NERC to consider the necessity of developing a similar implementation plan with respect to PER-005-1, Requirement R3.1.12

Consideration of Directive The PER ad hoc group was in agreement that a new subrequirement 3.1 should be developed in the PER-005 standard to address entities that may become subject to simulator training in the future. Further discussion was held regarding the best time frame for entities to become compliant, and the general consensus was that six months is a reasonable timeframe. This information was presented at webinars, conferences, and face-to-face meetings, and no feedback was received regarding the implementation plan of simulator training for entities. Technical Discussions The ad hoc group did not receive feedback regarding the implementation plan for simulation technology.

Applicability of the PER Standard to Local Transmission Control Center FERC Order 742 ¶ 64 Accordingly, we adopt our NOPR proposal and direct the ERO to develop through a separate Reliability Standards development project formal training requirements for local transmission control center operator personnel. Finally, given the numerous comments stating that term “local transmission control center” should be defined, we direct NERC to develop a definition of “local transmission control center” in the standards development project for developing the training requirements for local transmission control center operator personnel. We will not evaluate Associated Electric’s proposed definition but, rather, leave it to the ERO to develop an appropriate definition that reflects the scope of local transmission control centers. The Commission will not opine on the appropriate definition of local transmission control center, as this definition can be addressed first using NERC’s Reliability Standards Development Procedures. Consideration of Directive The ad hoc group considered whether to define local transmission control center in the NERC Glossary of Terms or create a standard-only definition. The group defined “local transmission control center” by extending the PER standard applicability to TOs and developing a definition that only applies to the PER standard. The suggested TO standard-only definition is personnel in a transmission control center who operate a portion of the BES at the direction of its Transmission Operator. Technical Discussions The group did not receive many comments regarding expanding formal training for local transmission control center operator personnel and defining local transmission control center. The group suggested a revision to PER-005-1 and created a standard-only definition of “local transmission control center.”

Other Issues Inconsistent usage of “each calendar year,” “annual,” and “at least every twelve months” The PER ad hoc group changed all terms (such as “annual” and “at least every twelve months”) to “each calendar year” due to “each calendar year” being better defined than the other two terms.

Definitions System Operator A SAR was submitted for GOPs to be removed from the System Operator definition. The ad hoc group removed the term and suggested a revised definition. The suggested definition is as follows: An individual at a cControl cCenter (Balancing

12 FERC Order 742 P 64



Authority, Transmission Operator, Generator Operator, Reliability Coordinator) whose responsibility it is to monitor and control who operates or directs the operation of the Bulk eElectric sSystem in Real time. System Personnel The term “System Personnel” was created as a standard-only definition for PER-005. The purpose of this definition is to capture certain applicable entities within the requirement instead of having to type each one out individually, multiple times, in a requirement. The suggested definition is as follows: System Operators of a Reliability Coordinator, Transmission Operator, or Balancing Authority, and the Transmission Owner personnel described in the Applicability Section of this standard. Support Personnel The term “System Personnel” was created as a standard-only definition for PER-005. The purpose of this definition is to capture certain applicable personnel within the requirement as a group for clarity. The suggested definition is as follows: Individuals who carry out outage coordination and assessments, or determine SOLs, IROLs, or operating nomograms for Real-time operations.

Conclusion


Conclusion The informal development initiative provided key discussions regarding the outstanding PER FERC directives. This white paper encapsulates all of the components of what is needed for the Standards Committee to act on, discuss, and ultimately authorize the PER Standard Authorization Request.

Appendix A: Industry Arguments and FERC Responses


Appendix A: Industry Arguments and FERC Responses The below table shows initial arguments received from industry regarding FERC Orders 693 and 742. Also shown below are the arguments received from industry to-date that are deemed to be the same arguments found in both orders.

EXTENDING APPLICABILITY TO GOPS

Industry Comment Order Cite FERC Response Order Cite Phase 2 Industry Comment

Clarification of Applicable GOPs

Many commenters requested clarification as to which GOPs needed to be trained:

1) FirstEnergy supported GOP training but noted there was some confusion over the GOP classification, which is sometimes used to refer to dispatch personnel (or fleet operators at a control center) and other times used to refer to a plant or unit operator. FirstEnergy requested that the Commission direct NERC to recognize this distinction.

2) California PUC, Nevada Companies, Reliant, Dynegy, MISO, and Wisconsin Electric all presented various arguments as to why training should not be extended to plant operators. These entities did not argue against application of the training standard to dispatch personnel.

Order No. 693 at PP. 1350, 1352-54

FERC clarified that the directive to train GOPs only applies to GOPs located at a dispatch center that receives direction and then develops specific dispatch instructions for plant operators under their control. FERC clarified that plant operators need not be trained under the standard.

Order No. 693 at PP. 1360-61

See also Order No. 742 at P. 83.





Decision-Making Arguments A number of commenters, including Xcel, argued that GOPs need not be trained because they do not make independent decision. They argued that GOPs simply take their direction from Transmission Operators, Balancing Authorities, and Reliability Coordinators, which limits their ability to exercise independent action impacting the reliability of the Bulk-Power System.

Order No. 693 at PP. 1351; 1354

FERC rejected this argument, stating:

“Xcel and others oppose extending the applicability of PER-002-0 to generator operators, because they take directions from balancing authorities and others, which limits their ability to impact reliability. Although a generator may be given direction from the balancing authority, it is essential that generator operator personnel have appropriate training to understand those instructions, particularly in an emergency situation in which instructions may be succinct and require immediate action. Further, if communication is lost, the generator operator personnel should have had sufficient training to take appropriate action to ensure reliability of the Bulk-Power System. Thus, we direct the ERO to develop a modification to make PER-002-0 applicable to generator operators.

Order No. 693 at P. 1359

Decision-Making Arguments A number of commenters, through verbal conversations and the chat feature during PER webinars, stated that all decisions that GOPs make that impact the BES must be approved by BA, TOP, or RC have the final say in the decisions being made.





No Reliability Benefit Argument Entergy, Xcel and Nevada companies further argued that generator operator training will provide limited benefit. Entergy further stated that that expanding the applicability to generator operators would provide little benefit to those personnel in the performance of their own functions, and could distract them from those functions.

Order No. 693 at P. 1351; 1357

FERC disagreed, stating that with the limitation of training to dispatch personnel, “the benefits to the Bulk-Power System will be maximized and the cost of formal training limited.”


No Reliability Benefit Argument Creating training for GOPs will be costly and provide no benefit.

Scarcity of Resources and Cost Argument Entergy argued that training would be extremely costly and would divert necessary resources from more important reliability objectives. TAPS also opposed the expanded applicability, especially in the case of small systems, because it believes that the requirement would be costly with no benefits to reliability.

Order No. 693 at P. 1351; 1357

See above. FERC rejected these arguments, stating that the limitation to dispatch personnel would limit the cost of training.


Scarcity of Resources and Cost Argument A number of commenters, through verbal conversations and the chat feature during PER webinars stated that it will be costly to train GOPs. Smaller entities state it will be a costly to provide training to their GOPs and no major benefits will appear.

Scope of Training Arguments

Many commenters discussed the scope of training for GOPs, arguing that the scope, content, and duration needs to be limited and tailored to their functions.


FERC agreed, stating that training for Generator Operators need not be as extensive as that required for Transmission Operators, and the training requirements developed by the ERO should be tailored in their scope, content, and duration so as to be appropriate to Generation Operations personnel and the objective of promoting system reliability.


Scope of Training Arguments

Concerns about GOPs that do not develop dispatch instructions will be captured regardless.





Size Limitation Arguments

APPA, TAPS, and the Process Electricity Committee requested a size limitation, arguing that while a generator plays an important role in the reliable operations of the Bulk Electric System, the Generator Operator takes commands from the Rransmission Operator, Balancing Authority, or Reliability Coordinator. Without a size limitation, the standard would require many small generators to enroll in a training program.


FERC responded that concerns regarding the need for a size limitation on Generator Operators should be satisfied by FERC’s determination that the applicability of particular entities should be determined based on the ERO compliance registry criteria.


Size Limitation Arguments

Comments received stated that a size limitation needs to be captured like CIP V5.

In response to the Order No. 742 NOPR, a number of commenters challenged the need for the directive.


FERC rejected these arguments as beyond the scope of Order No. 742 and as collateral attacks on the ruling in Order No. 693 and refused to address the arguments again.

Order No. 742 at PP. 79, 81





EPSA Clarification

EPSA sought clarification regarding the statement in the NOPR, “[I]n the event communication is lost, the generator operator personnel must have had sufficient training to take appropriate action to ensure reliability of the Bulk-Power System.” EPSA expressed concern that this statement suggests that if communication is lost with the grid operator, the Generator Operator must take unilateral action for which it requires training. EPSA notes that Generator Operators do not take such unilateral action, nor do they have access to information to make such decisions. EPSA asks the Commission to make clear that while communication should be addressed in training requirements for centrally located Generator Operator dispatch employees, the Commission is not extending related responsibilities or training requirements to Generator Operator employees.


FERC granted the requested clarification and affirmed that it did not modify the Order No. 693 directive regarding training for certain Generator Operator dispatch personnel, nor expand a Generator Operator’s responsibilities.




EXTENDING APPLICABILITY TO SUPPORT PERSONNEL

Industry Comment Order Cite FERC Response Order Cite Phase 2 Industry Comments

No Reliability Benefit

EEI states that the extension of the applicability to “operations support personnel” could result in a dramatic expansion of industry training requirements with uncertain benefits to system reliability.


FERC stated that because it is limiting training of support personnel to those who carry out outage coordination and assessments and those who determine SOLs and IROLs or operating nomograms, the directive is limited to those with a direct impact on reliability.

Order No. 693 at P. 1374 No Reliability Benefit

A number of commenters, through verbal conversations and the chat feature during PER webinars, stated that expanding PER-005 applicability to support personnel will capture a variety of people who do not impact the BES.

TOP makes decision Entergy argued that it is unnecessary to require all staff supporting the Transmission Operator to be trained in the Transmission Operator’s Reliability Standards responsibilities, because as long as the supporting personnel work under the direction of a NERC-certified Transmission Operator, there is no need for duplicative training for supporting personnel.


FERC stated that because it is limiting training of support personnel to those who carry out outage coordination and assessments and those who determine SOLs and IROLs or operating nomograms, the directive is limited to those with a direct impact on reliability.

Order No. 693 at P. 1374 TOP makes decision A number of commenters, through verbal conversations and the chat feature during PER webinars, stated that decisions are made by the NERC-Certified System Operators.

Administrative Burden

APPA expressed concern about expanding the applicability to operations planning and operations support staff, especially if the Commission adopts its proposed interpretation of the Bulk Electric System, because this would become quite onerous for small utilities.


FERC limited the scope of what support personnel must be trained and clarified that training for support personnel should be tailored to the functions they perform and need not be trained to the same extent as Transmission Operators.

Order No. 693 at P 1375 Administrative Burden

A number of commenters, through verbal conversations and the chat feature during PER webinars, stated that this would be a huge administrative burden regarding the SAT process.





Directive is Ambiguous

Wisconsin Electric argued that the Commission’s proposal does not address how to identify the operations planning and operations support personnel who would be subject to the Reliability Standard and how to develop compliance measures for them. It contended that the proposed modification is ambiguous and should not be implemented. Northern Indiana also argued that the terms “operations planning” and “operations support staff” should be clarified.


FERC clarified that the support personnel who need to be trained are those who carry out outage coordination and assessments in accordance with Reliability Standards IRO-004-1 and TOP-002-2, and those who determine SOLs and IROLs or operating nomograms in accordance with Reliability Standards IRO-005-1 and TOP-004-0. FERC said that because the reliability impact of EMS personnel are unclear, it directed NERC to consider whether such personnel need to be trained.


Directive is Ambiguous A number of commenters, through verbal conversations and the chat feature during PER webinars, stated that “operations planning” and “operations support” are too broad.

Scope of Training

Entergy commented that if training is required, it should focus on the functions operations planning and operations support staff must perform, not on the functions that others perform.


FERC clarified that training for support personnel should be tailored to the functions they perform and need not be trained to the same extent as transmission operators.

Scope of Training





No Reliability Benefit

In response to the Order No. 742 NOPR, a number of commenters challenged the need for the directive. For example, Associated Electric urged the Commission to direct NERC to adopt a definition of “operations planning” and “operations support staff” that more narrowly identifies those personnel who will be subject to the training standard. Associated Electric stated that the directive in Order No. 693 is broad and will encompass operations planning and operation support staff who engage in tasks that do not directly affect the reliable operation of the Bulk Electric System.

GSOC and GTC do not support expanding the applicability of the PER-005-1 training requirements to any other personnel and argue that time spent expanding training requirements to other personnel will take away from their job of supporting their operating personnel—a use of time and resources that could actually decrease reliability.


FERC rejected these arguments as beyond the scope of Order No. 742 and as collateral attacks on the ruling in Order No. 693 and refused to address the arguments again.

Order No. 742 at PP. 79, 81 No Reliability Benefit

A number of commenters, through verbal conversations and the chat feature during PER webinars, stated that tasks performed by support personnel do not directly affect the BES. Support personnel may guide, but do not operate.

Appendix B: Entity Participants


Appendix B: Entity Participants The below nonexhaustive list represents entities that had personnel who participated in the PER informal development effort in some manner, which may include one of the following: direct participation on the ad hoc group, inclusion on the wider distribution (the “plus”) list, attendance at workshops or other technical discussions, participation in a webinar or teleconference, or by providing feedback to the group through a variety of methods (e.g., email, phone calls, etc.). Additionally, announcements were distributed to wider NERC distribution lists to provide the opportunity for entities that were not actively participating to join the effort.

Table 2: Entity Participation in PER Informal Development

ACES Power CPS Energy IESO NV Energy Southern Co.

AECI CSU IMPA OGE STEC

AEP CWLP Integry Group OMU Sunflower

AES DC PUD IREA ORU Sycamore

ALCOA Detroit Renewable ISO-NE OUC TID

Alliant Energy Direct Energy ITC OXY Tri-State G&T

Ameren Dominion KCPL PacifiCorp TVA

AMP Partners DTE Energy KUA PEPCO APS Duke Energy LCEC PGE ATC Dynegy LCRA PGN Regional Entities

Austin Energy Energy GRP LES PJM FRCC

Blackhills Corp Entergy LGE-KU PNM MRO

BPA EP Electric Luminant PNM Resources NPCC

Brazos Electric ERCOT MGE PPL RFC

Brownsville PUD Essential Power LLC MidAmerican Seattle Power & Light

SERC

CAISO Exelon Corp Minnkota Power Sempra Utilities SPP

CB Power FMTN MISO Energy Sharyland TRE Center Point Energy FPL NaturEner SMEPA

WECC

Chelan PUD GASOC NIPSCO SMMPA City of Tacoma GC Pud Northwestern SMUD City Utilities Hydro Manitoba NRECA Snohomish PUD Cleco

Corporation Hydro-Quebec NU South Westgen

Table 3: Presentations and Events NERC Operating Committee FRCC Compliance Workshop

NERC EAS WECC Operations Training Subcommittee

NERC Standards and Compliance Workshop WECC Standing Committees

NERC News TRE Standards Discussion Forum


Project 2010-01 Standard Drafting Team (SDT) Anticipated Date Location Event

July 2013 - SC Authorizes SAR and Pro Forma Standard for Posting

July 2013

Conduct Nominations for Project 2012-05 SDT

July 2013 - Post SAR and Pro Forma standard for 45-Day Comment

Period



September 2013 San Francisco PER Standard Drafting Team Face to Face Meeting to

Respond to Initial Comments and Make Possible Revisions




Authorities


July 18, 2013

VAR Informal Development Project Requested Action

1. Authorize the concurrent posting of the VAR Standards Authorization Request (SAR) for a 45-day informal comment period (given it is addressing FERC directives) along with the revised VAR reliability standards (proposed VAR-001-4 and VAR-002-3), VRFs/VSLs, and associated implementation plan for a 45-day comment period with a ballot pool formed during the first 30 days of the comment period, and a ballot and non-binding poll conducted during the last ten days of that comment period; and

2. Approve the posting for a 10-day solicitation for nominations for Standard Drafting Team members for VAR’s formal development.

The VAR project will be assigned a project number prior to posting. Background On November 24, 2009, FERC issued Order No. 693 which approved earlier versions of the VAR standards; however, Order No. 693 also issued several directives requiring the VAR standards to be modified in order to improve reliability. From Order No. 693, there are several outstanding directives that are addressed in detail in the technical white paper contained in the SAR package. The informal consensus building for VAR began in February 2013. Specifically, the ad hoc group engaged stakeholders on how best to address the FERC directives, paragraph 81 criteria, and results-based approaches. A discussion of the ad hoc group’s consensus building and collaborative activities are included in the technical paper (see SAR package). The ad hoc group applied the Paragraph 81 criteria in reviewing the existing standards; identifying those requirements that had little to no impact to reliability. (See Mapping Document for the cross-reference to requirements that were eliminated due to redundancies with other standards.) Based on stakeholder outreach, the informal ad hoc group is presenting a pro forma standard that addresses the FERC directives for both of the VAR-001 and VAR-002 standards. VAR-001 addresses a majority of the FERC directives from Order No. 693, but as explained above has eliminated several requirements. VAR-002 has also been modified to add a new timeframe for notifications to the relative Transmission Operators to address both a FERC directive and to address certain operational processes. Due to the number of eliminations in the proposed standards, and due to the use of a new standard template, a redline is not included in today’s materials. Please refer to the Mapping Document to review changes in the standards. In addition, the WECC variance for VAR-001 is being retained; thus, that particular standard will continue to apply to Generator Operators within WECC region. The goal is to present the VAR standards to the NERC Board of Trustees during its November 2013 meeting, and for the Board adopted VAR-001-4 and VAR-002-3 to be filed with the applicable regulatory authorities by the end of 2013.


July 18, 2013 Standard Drafting Team The VAR drafting team is proposed to consist of a maximum of 10 members. Since this project is a continuation of informal development, several drafting team members will be selected from members of the informal group and the remainder from industry. A confidential slate of candidates with recommendations for appointment will be provided following the public solicitation. The purpose of this appointment/solicitation approach is to ensure a smooth transition from the informal to formal standards development process for VAR, while also providing an opportunity for solicitation of new members to help provide a well-rounded perspective to moving VAR forward. The public solicitation shall request that standard drafting team members have experience in one or more of the following areas: transmission operations, transmission planning, reliability coordinating, and generator operation. In addition, team members with experience in compliance, legal, regulatory, and technical writing is desired. Previous drafting team experience is beneficial, but not a requirement. Quality Review A quality review was coordinated by NERC staff for the posting of the pro forma standard. Project Schedule The drafting team is expected to facilitate meeting the proposed schedule contained in the SAR package.

VAR SAR Package Submittal to the


July 18, 2013



VAR Standards Committee Package - Contents Bookmark Description


Request

An informal development ad hoc group is presenting a pro forma standard that consolidates modifies the existing VAR-001-3 and VAR-002-2b. The standards protect voltage stability by ensuring voltage levels, reactive flows, and reactive resources are monitored, controlled, and maintained.

Pro Forma Standard

The pro forma standard is the result of significant industry outreach. The WECC variance to VAR-001-3 is retained, but the standards have also been streamlined consistent with Paragraph 81 tenets and results-based standards initiative.


Implementation Plan

The implementation plan gives the overview of how the existing standards will be tied to the effective date of the pro forma standard.

Mapping Document

The mapping document correlates the requirements within the existing VAR standards to the requirements within the pro forma.

Technical White Paper

The purpose of this white paper is to provide background and technical rationale for the proposed revisions to the group of approved VAR standards that have a common mission of providing voltage stability.




NERC welcomes suggestions to improve the

reliability of the bulk power system through

improved reliability standards. Please use this form

to submit your request to propose a new or a

revision to a NERC’s Reliability Standard.


Title of Proposed Standard: Voltage and Reactive Control; Generator Operation for Maintaining

Network Voltage Schedules



Name: Soo Jin Kim

Organization: NERC



New Standard



Urgent Action

SAR Information


Resolve FERC directives from FERC Order No. 693 and improve upon the existing VAR standards.


The pro forma standard consolidates the reliability components of the existing VAR-001 standard, adds

new requirements to address FERC’s directives in Order No. 693, and provides a non-compliance

window in VAR-002 notification requirements.


[email protected]

mailto:[email protected]


Standards Authorization Request

July 18, 2013 2

SAR Information

Identify the Objectives of the proposed standard’s requirements (What specific reliability deliverables

are required to achieve the goal?):

The objectives are to address the outstanding directives from FERC Order 693 and added a non-

compliance window for when a GOP must notifiy a TOP when a unit is deviating from a voltage

schedule.


The drafting team will answer the outstanding VAR directives from FERC Order No. 693. The VAR-001 directives are summarized from P 1880 of Order No. 693 as:

o Expand the applicability to include reliability coordinators and LSEs; o Include detailed and definitive requirements on “established limits” and “sufficient

reactive resources” and identify acceptable margins above the voltage instability points; o Include Requirements to perform voltage stability analysis periodically, using online

techniques where commercially available and offline techniques where online techniques are not available, to assist real-time operations, for areas susceptible to voltage instability;

o Include controllable load among the reactive resources to satisfy reactive Requirements; and

o Address the power factor range at the interface between LSEs and the transmission grid.

The VAR-002 directive is to simply consider adding more detail around what would constitute an incident of non-compliance for a Generator.

The drafting team will also modify the VAR-002 standard in order to address some of the numerous notifications that are required by the currently enforceable standard.





Detailed description of this project can be found in the Attachment (pro forma VAR standards) and

White Paper of this SAR submittal package.




July 18, 2013 3




Organization








Balancing Authority














Provider



tariff).


Transmission

Operator






Purchasing-Selling Purchases or sells energy, capacity, and necessary reliability-related



July 18, 2013 4


Entity services as required.









defined limits through the balancing of real and reactive power supply and demand.













Principles?

Enter

(yes/no)


Yes


Yes


Yes

4. A reliability standard shall not require the public disclosure of commercially sensitive information. All market participants shall have equal opportunity to

Yes



July 18, 2013 5


access commercially non-sensitive information that is required for compliance with reliability standards.

Related Standards


VAR-001- 3 Voltage and Reactive Control

VAR-002-2b Generator Operation for Maintaining Network Voltage Schedules

Related SARs

SAR ID Explanation

Project 2008-01 Voltage and Reactive Planning and Control

Regional Variances

Region Explanation

ERCOT None

FRCC None

MRO None



July 18, 2013 6

Regional Variances

NPCC None

RFC None

SERC None

SPP None

WECC VAR-001-3 WECC variance is retained.

VAR-001-4 — Voltage and Reactive Control

July 18, 2013 Page 1 of 13



Development Steps Completed 1. SAR posted for comment on July 19, 2013

Description of Current Draft This draft standard is concluding informal development and will move to formal development when authorized by the Standards Committee.


SAR Authorized by the Standards Committee July

45-Day Posting for SAR and the Pro Forma Standard’s Initial Comment and Ballot Opens

July

Nomination Period Opens July

Standard Drafting Team Appointed July

45-Day Posting for SAR and Initial Comment and Ballot Closes August

Final Ballot Opens October

Final Ballot Closes October

BOT Adoption November

Filing to Applicable Regulatory Authorities December


July 18, 2013 Page 2 of 13

Effective Dates

In those jurisdictions where regulatory approval is required, this standard shall become effective on the first day of the first calendar quarter after applicable regulatory approval or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities. In those jurisdictions where no regulatory approval is required, this standard shall become effective on the first day of the first calendar quarter after Board of Trustees approval.

Version History


1 6/18/2007 Initial Standard is FERC approved

2 1/10/2011 FERC approved added LSEs and

Controllable Load to the standard.

3 6/20/2013 WECC Variance is approved by FERC


July 18, 2013 Page 3 of 13

Definitions of Terms Used in the Standard

None.


July 18, 2013 Page 4 of 13

Introduction

1. Title: Voltage and Reactive Control

2. Number: VAR-001-4

3. Purpose: To ensure that voltage levels, reactive flows, and reactive resources are monitored, controlled, and maintained within limits in real time to protect equipment and the reliable operation of the Interconnection.

4. Applicability:

4.1. Transmission Operators

4.2. Reliability Coordinators

4.3. Generator Operators within the Western Interconnection


July 18, 2013 Page 5 of 13

Requirements and Measures

R1. Each Transmission Operator shall have documented policies or procedures that are implemented to establish, monitor, and control voltage levels and Reactive Power flows (Mvar flows) within limits as defined below. [Violation Risk Factor: High] [Time Horizon: Operations]

1.1. These documented policies or procedures shall include criteria used in system assessments. The criteria for the assessments shall include established steady-state limits, voltage stability limits and associated operating margins, and voltage schedules along with associated tolerance bands.

1.2. Each Transmission Operator shall provide a copy of these documented policies or procedures to adjacent Transmission Operators.

1.3. Each Transmission Operator shall provide a copy of these documented policies or procedures to its Reliability Coordinator.

M1. The Transmission Operator shall have evidence of documented policies or procedures as specified in Requirement 1. As stated in R1, the policies and procedures must detail how criteria for steady-state and voltage stability limits are used in the Transmission Operator’s assessments of the system. In order to demonstrate the Transmission Operator is implementing the policies or procedures, the Transmission Operator must be able to provide evidence that proves voltage is currently being monitored. Such evidence may include, but is not limited to: 1) proof that points are telemetered, 2) alarms are functioning, and 3) during events of low or high voltage the policies and procedures are being followed to respond to control voltage levels. The Transmission Operator must also provide evidence that the policies or procedures were communicated to adjacent Transmission Operators and to its Reliability Coordinator. Evidence may include, but is not limited to, emails, website postings, and meeting minutes. Simply posting a copy of the policies or procedure on a public website is not sufficient if the Transmission Operator and Reliability Coordinator were not notified as to where to find the policies or procedures.

Rationale for R1: This requirement will allow each Transmission Operator (TOP) to establish its own policies and procedures, and the criteria for periodic updates will be individualized based on the stability of each TOP's regions. The language is refined to show that coordination with neighboring TOPs is required. It also states TOP shall provide data to the Reliability Coordinator (RC) for its monitoring functions to respond to address the FERC directive in P 1855 of Order No. 693, which directed NERC to add RC monitoring to the VAR standards. P 1868 requires NERC to add more "detailed and definitive requirements to include more detailed and definitive requirements on “established limits” and “sufficient reactive resources” and identify acceptable margins (i.e. voltage and/or reactive power margins)."


July 18, 2013 Page 6 of 13

R2. Each Transmission Operator and Reliability Coordinator shall perform assessments on their respective areas in order to ensure sufficient reactive resources are available for scheduling to maintain voltage stability under normal and contingency conditions in order to provide the voltage levels as defined in Requirement R1. [Violation Risk Factor: High] [Time Horizon: Operations]

2.1. Each Transmission Operator shall operate or direct the real-time operation of devices necessary to regulate transmission voltage and reactive flow necessary to regulate transmission voltage and reactive flow which may include, but is not limited to reactive generation scheduling; transmission line and reactive resource switching; controllable load; and, if necessary, load shedding, to maintain system voltages within established limits.

2.2. As a result of the assessments, each Transmission Operator shall ensure that sufficient reactive resources have been scheduled to meet acceptable day-ahead voltage limits identified in Requirement R1. Sufficient reactive resources may include, but is not limited to reactive generation scheduling; transmission line and reactive resource switching; and controllable load.

M2. Each Transmission Operator and Reliability Coordinator shall have evidence of current or past studies used to schedule sufficient reactive resources. Each Transmission Operator shall also provide proof that additional resources were scheduled when necessary. During a real-time event where voltage must be adjusted, a Transmission Operator shall show evidence to show directions were given to adjust the operation of capacitive and inductive resources. This may include directions to Generator Operators to operate within new tolerance bands or to make manual adjustments if necessary. Transmission Operators shall also have evidence to show proof of directing new resources to come online. Those resources can include, but is not limited to capacitor banks, switching, adjusting controllable load, and when necessary load can be shed. For the day-ahead scheduling, Transmission Operators shall provide copies of provide day-ahead studies used to schedule enough resources to meet expected voltage requirements.

Rationale for R2:

P 1875 from Order No. 693 directed NERC to include requirements to run voltage stability analysis periodically. The informal ad hoc group and industry participants concluded that the best models and tools are the ones that have been proven over time, and that the requirement should not require any utility to purchase new online simulations tools. Therefore, the new requirement does not specify when to use online tools. The sub-requirements detail the real-time and day-ahead assessments necessary under R1. The existing VAR-001 also requires a list of sufficient reactive resources; this was retained in the proposed requirement as FERC determined in a letter order that this list answered the directive in P 1868 to detail the list of "sufficient reactive resources." Controllable load is specifically included to answer FERC's directive in P 1879.


July 18, 2013 Page 7 of 13

R3. The Transmission Operator shall specify the criteria that will exempt generators from compliance with the requirements defined in Requirement 4 and any associated notification requirements. [Violation Risk Factor: Lower] [Time Horizon: Operations]

3.1. In the event a Transmission Operator approves a generator as satisfying the criteria, it shall notify the associated Generator Operator.

M3. Each Transmission Operator shall have evidence of the documented criteria for generator exemptions. The Transmission Operator shall also have evidence to show that, for each generating unit in its area that is exempt from following a voltage or Reactive Power schedule, the associated Generator Owner was notified of this exemption in accordance with Requirement 3. Temporary exemptions maybe provided to generators during scenarios where notifications/communications are not necessary due to a system event that prevents a Generator Operator from maintaining a schedule. Similarly, when an Automatic Voltage Regulator (AVR) is malfunctioning, which prevents a Generator Operator from maintaining a voltage schedule and tolerance band, temporary exemptions may be provided. For temporary exemptions, evidence showing the exemptions were granted must be provided. If the exemptions were given verbally from the Transmission Operator, the phone recordings or emails commemorating the phone call must be provided. For temporary exemptions, the evidence of communication must also include the timeframe for how long the exemption will last.

R4. Each Transmission Operator shall specify a voltage or Reactive Power schedule and tolerance band (at either the high side or low side of the Generator Step-Up transformer at the TOP's discretion)

Rationale for R4:

The new requirement adds “tolerance band” in order to provide more detailed information when establishing limits.

Rationale for R3:

These exemptions offer TOPs the option to exempt certain generators during maintenance or system events when those units are not able to maintain voltage schedules. Sub-requirements containing an exemption list were removed from the existing standard because this created more compliance issues with regard to how often the list would be updated and maintained.


July 18, 2013 Page 8 of 13

at the interconnection point between the generator facility and the Transmission Owner's facilities to be maintained by each generator. [Violation Risk Factor: Medium] [Time Horizon: Operations]

4.1. The Transmission Operator shall provide the voltage or Reactive Power schedule and tolerance band to the associated Generator Operator and direct the Generator Operator to comply with the schedule in automatic voltage control mode (the AVR is in service and controlling voltage).

M4. The Transmission Operator shall have evidence it provided a voltage or Reactive Power schedule and tolerance band as specified in Requirement 4 to the applicable Generator Operators. For real-time directives, evidence may include recorded phone logs.

R5. The Transmission Operator shall know the status of all transmission Reactive Power resources, automatic voltage regulators, and power system stabilizers in their system. [Violation Risk Factor: Medium] [Time Horizon: Operations]

M5. The Transmission Operator shall have evidence to show Reactive Power resources are being monitored. Evidence may include, but is not limited to screen shots of EMS/SCADA data, alarms, and phone logs. In the event the monitoring system does not work, each Transmission Operator should have a protocol in place to show these resources are being monitored.

R6. After consultation with the Generator Owner regarding necessary step-up transformer tap changes, the Transmission Operator shall provide documentation to the Generator Owner specifying the required tap changes, a timeframe for making the changes, and technical justification for these changes. [Violation Risk Factor: Lower] [Time Horizon: Operations]

M6. The Transmission Operator shall have evidence that it provided documentation to the Generator Owner when a change was needed to a generating unit’s step-up transformer tap in accordance with the requirement.

Rationale for R6:

Although tap settings are first established at interconnection, this requirement could not be deleted because no other standard addresses when a tap setting must be adjusted. If the tap setting is not properly set, then the amount of VARs produced by a unit can be affected.

Rationale for R5:

Since power system stabilizers (PSS) equipment is not highlighted in any other standard, the VAR standard is the appropriate place to ensure the equipment is being monitored. This requirement is not duplicative of the TOP standards because the voltage regulators and power system stabilizer are highlighted.


July 18, 2013

Compliance

1. Compliance Monitoring Process:

1.1. Compliance Enforcement Authority:


1.2. Evidence Retention:

The Transmission Operator shall retain evidence for Measures 1 through 4 for 12 months. The Compliance Monitor shall retain any audit data for three years.


As defined in the NERC Rules of Procedure, “Compliance Monitoring and Assessment Processes” refers to the identification of the processes that will be used to evaluate data or information for the purpose of assessing performance or outcomes with the associated reliability standard.

1.4. Additional Compliance Information:

• None


July 18, 2013 Page 10 of 13


R # Time Horizon



R1 Operations High

The Transmission Operator has documented criteria for assessments, but has provided a copy to only one of the parties that should have received a copy (either a neighboring TOPs or its RC).

The Transmission Operator has documented policies and procedures, but has not provided copies to either the neighboring TOPs or its RC.

The Transmission Operator has documented policies or procedures, but none of the sub-requirements were followed.

The Transmission Operator has no documented policies or procedures.

R2 Operations

High N/A The Transmission Operator only performs day-ahead assessments and only schedules day-ahead resources.

N/A The Transmission Operator does not perform assessments and therefore does not have policies and procedures implemented to have sufficient Mvars. A lack of real-time operations is also severe.

R3 Operations Planning

Lower N/A N/A N/A The Transmission Operator does not have exemption criteria.

R4 Operations Medium N/A N/A The Transmission Operator provides voltage or Reactive Power schedules to only some of the GOPs.

The Transmission Operator does not provide voltage or Reactive Power schedules and tolerance bands at all.


July 18, 2013 Page 11 of 13

R # Time Horizon



R5 Operations Lower N/A The Transmission Operator is unaware of the status in a stable area.

The Transmission Operator does not know the status of important equipment in weaker areas that were identified in assessments as part of R1.

N/A

R6 Operations Lower Either the technical justification or timeframe are not provided.

Neither the technical justification nor the timeframe are provided.

N/A N/A


July 18, 2013

Regional Variances

Regional Variance for the Western Electricity Coordinating Council from VAR-001-3 is retained.

Interpretations

None.

Associated Documents

None.


July 18, 2013 Page 13 of 13


For technical basis for each requirement, please see the VAR White Paper for further technical information.

VAR-002-3 — Generator Operation for Maintaining Network Voltage Schedules

July 18, 2013 Page 1 of 14



Development Steps Completed 1. SAR posted for comment on July XX, 2013

Description of Current Draft This draft standard is concluding informal development and will move to formal development when authorized by the Standards Committee.


SAR Authorized by the Standards Committee July

45-Day Posting for SAR and the Pro Forma Standard’s Initial Comment and Ballot Opens

July

Nomination Period Opens July

Standard Drafting Team Appointed July

45-Day Posting for SAR and Initial Comment and Ballot Closes August

Final Ballot Opens October

Final Ballot Closes October

BOT Adoption November

Filing to Applicable Regulatory Authorities December


July 18, 2013 Page 2 of 14

Effective Dates

In those jurisdictions where regulatory approval is required, this standard shall become effective on the first day of the first calendar quarter after applicable regulatory approval or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities. In those jurisdictions where no regulatory approval is required, this standard shall become effective on the first day of the first calendar quarter after Board of Trustees approval.

Version History


1 5/1/2006 Added “(R2)” to the end of levels on

non-compliance 2.1.2, 2.2.2, 2.3.2, and 2.4.3.

July 5, 2006

1a 12/19/2007 Added Appendix 1 – Interpretation of R1 and R2 approved by BOT on August

1, 2007 Revised

1a 1/16/2007 In Section A.2., Added “a” to end of

standard number.

Section F: added “1.”; and added date. Errata

1.1a 10/29/2008 BOT adopted errata changes; updated

version number to “1.1a” Errata

1.1b 3/3/2009 Added Appendix 2 – Interpretation of

VAR-002-1.1a approved by BOT on February 10, 2009

Revised

2b 4/16/2013

Revised R1 to address an Interpretation Request. Also added previously

approved VRFs, Time Horizons and VSLs. Revised R2 to address

consistency issue with VAR-001-2, R4. FERC Order issued approving VAR-002-

2b.

Revised


July 18, 2013 Page 3 of 14

Definitions of Terms Used in the Standard

None.


July 18, 2013 Page 4 of 14

Introduction

1. Title: Generator Operation for Maintaining Network Voltage Schedules

2. Number: VAR-002-3

3. Purpose: To ensure 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.

4. Applicability:

4.1. Generator Operator

4.2. Generator Owner


July 18, 2013 Page 5 of 14

Requirements and Measures

R1. The Generator Operator shall operate each generator connected to the interconnected transmission system in the automatic voltage control mode (with its automatic voltage regulator (AVR) in service and controlling voltage) unless the Generator Operator has notified the Transmission Operator of one of the following: [Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]

• That the generator is being operated in start-up1 or shutdown2

• That the generator is not being operated in the automatic voltage control mode for a reason other than start-up or shutdown.

mode pursuant to a Real-time communication or a procedure that was previously provided to the Transmission Operator; or

M1. The Generator Operator shall have evidence to show that it notified its associated Transmission Operator any time it failed to operate a generator in the automatic voltage control mode as specified in Requirement 1. If a generator is being started up or shut down with the automatic voltage control off and no notification of the automatic voltage regulator status is made to the Transmission Operator, the Generator Operator will have evidence that it notified the Transmission Operator of its procedure for placing the unit into automatic voltage control mode. Such evidence must include, but is not limited to, dated evidence of transmittal of the procedure such as an electronic message or a transmittal letter with the procedure included or attached.

1 Start-up is deemed to have ended when the generator is ramped up to its minimum continuously sustainable load and the generator is prepared for continuous operation. 2 Shutdown is deemed to begin when the generator is ramped down to its minimum continuously sustainable load and the generator is prepared to go offline.

Rationale for R1: This requirement has been maintained due to the importance of running a unit with its automatic voltage regulator (AVR) in service and in voltage controlling mode. The measure has been updated include some of the evidence that can be used for Compliance purposes.


July 18, 2013 Page 6 of 14

R2. Unless exempted by the Transmission Operator, each Generator Operator shall maintain the generator voltage or Reactive Power schedule3 (within applicable Facility Ratings4

2.1. If a GOP drifts out of schedule, each Generator Operator shall notify its associated Transmission Operator within 15 minutes when both of the following conditions are met: 1) the GOP is operating outside of the prescribed voltage or Reactive Power schedule tolerance band

) as directed by the Transmission Operator. [Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]

5

2.2. When a generator’s automatic voltage regulator is out-of-service, the Generator Operator shall use an alternative method to control the generator reactive output to meet the voltage or Reactive Power schedule directed by the Transmission Operator.

for 15 minutes; and 2) the GOP is no longer able to return to its voltage or Reactive Power schedule.

2.3. When directed to modify voltage, the Generator Operator shall comply or provide an explanation of why the schedule cannot be met.

M2. Generator Operators will still make all attempts to operate within the tolerance bands provided by the TOP, but natural drifting may occur. In instances where there is an event occurring to pull a unit out of the tolerance band, the Generator Operator will not be held in non-compliance with this requirement if the sub-requirements 2.1, 2.2, and 2.3 are met. In order to identify when a unit is deviating from its schedule, GOPs will monitor voltage based on existing equipment at its facility. Therefore, GOPs have the option to operate on a voltage schedule on either the high-side or convert the high-side schedule to a low-side schedule at the GOP’s discretion. For units that monitor on the low-side/terminal voltage, Generator Operators shall provide evidence of the method of conversion from the high-side schedule to low-side monitoring. For sub-requirement 2.1, most units will not be able to return to schedule due to a limiting factor. Such limiting factors may include, but are not limited to: 1) terminal voltage, 2) bus voltage, 3) equipment temperature,

3 The voltage or Reactive Power schedule is a target value communicated by the Transmission Operator to the Generator Operator establishing a tolerance band within which the target value is to be maintained during a specified period. 4 When a Generator is operating in manual control, reactive power capability may change based on stability considerations and this may lead to a change in the associated Facility Ratings. 5 GOPs monitor and control voltage based on their equipment limitations. GOPs will monitor their voltage or Reactive Power schedule tolerance bands either at the high-side or low-side/terminal voltage.

Rationale for R2:

R2 details how a Generator Operator (GOP) operates the system to a maintain voltage schedule and when the GOP is expected to notify the Transmission Operator (TOP). Sub-requirement 2.1 provides guidance on a non-compliance window in the event a unit is deviating from schedule, and the GOP must notify the TOP if it is unable to return to schedule. Thus, the non-compliance window allows for notifications when a unit is unable to provide additional VAR support (e.g., when hitting an operational limit) or when the unit is too small to raise voltage. In both instances, the TOP may then provide some type of temporary exemption as outlined in VAR-001.


July 18, 2013 Page 7 of 14

4) transformer, 5) auxiliary equipment, 6) Volts/Hz limits, and 7) excitation or regulator limits. GOP shall have evidence to show compliance with requirement R2 by providing 1) Communications with the TOP when the Generator Operator was operating outside of the prescribed voltage or Reactive Power schedule tolerance band for 30 minutes or less (the 30 minutes allow for 15 minutes to call and 15 minutes to be outside of the tolerance band) AND Generator Operator is no longer able to return to its voltage or Reactive Power schedule; 2) Generator Operator implemented an alternative method to control reactive output when the AVR was out-of-service or unavailable; 3) compliance with directive to modify voltage or a notification that the directive could not be met. Evidence may include, but is not limited to Generator Operator logs, SCADA data, phone logs, and any other alarming notifications that would alert the Transmission Operator that both conditions were met. Timing for Requirement R2.1 is crucial, and Generator Operators are expected to begin timing an event as soon as the unit is operating outside of the tolerance band. Further, voltage documentation during a system event may be requested by an auditor to show measures were taken to bring the unit back into schedule.

R3. Each Generator Operator shall notify its associated Transmission Operator of a status or capability change on any generator Reactive Power resource, including the status of each automatic voltage regulator and power system stabilizer and the expected duration of the change in status or capability within 30 minutes of the change. If the status has been restored within the first 15 minutes of such change, then there is no need to call the TOP. [Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]

M3. The Generator Operator shall have evidence it notified its associated Transmission Operator within 30 minutes of any of the changes identified in Requirement 3. If the status has been restored within the first 15 minutes, no call is necessary; therefore, if a status on Reactive Power resource has changed, and that change lasts greater than 15 minutes, the GOP must notify its associated TOP within 30 minutes of when the change first occurred.

Rationale for R3:

This requirement has been modified to reduce the number of violations for when an AVR goes out-of- service and then comes back in-service. Fifteen (15) minutes have been built into the requirement to allow a Generator Operator time to resolve an issue before having to notify the Transmission Operator of a status or capability change. The requirement has also been amended to remove the sub-requirement to provide an estimate for the expected duration of the status change. The 15-minute window should resolve most issues, and further trouble-shooting will probably be required if the status change is unresolved within 15 minutes.


July 18, 2013 Page 8 of 14

R4. The Generator Owner shall provide the following to its associated Transmission Operator and Transmission Planner within 30 calendar days of a request. [Violation Risk Factor: Lower] [Time Horizon: Real-time Operations]

4.1. For generator step-up transformers and auxiliary transformers with primary voltages equal to or greater than the generator terminal voltage:

4.1.1. Tap settings.

4.1.2. Available fixed tap ranges.

4.1.3. Impedance data.

M4. The Generator Owner shall have evidence it provided its associated Transmission Operator and Transmission Planner with information on its step-up transformers and auxiliary transformers as required in Requirements 4.1.1 through 4.1.3.

R5. After consultation with the Transmission Operator regarding necessary step-up transformer tap changes, the Generator Owner shall ensure that transformer tap positions are changed according to the specifications provided by the Transmission Operator, unless such action would violate safety, an equipment rating, a regulatory requirement, or a statutory requirement. [Violation Risk Factor: Lower] [Time Horizon: Real-time Operations].

5.1. If the Generator Operator can’t comply with the Transmission Operator’s specifications, the Generator Operator shall notify the Transmission Operator and shall provide the technical justification.

M5. The Generator Owner shall have evidence that its step-up transformer taps were modified per the Transmission Operator’s documentation as identified in Requirement 5. The Generator Operator shall have evidence that it notified its associated Transmission Operator when it couldn’t comply

Rationale for R4:

This requirement and corresponding measure language has been maintained due to the importance of having accurate tap settings. If the tap setting is not properly set, then the amount of VARs produced by a unit can be affected.

Rationale for R5:

This requirement and corresponding measure language has been maintained due to the importance of having accurate tap settings. If the tap setting is not properly set, then the amount of VARs produced by a unit can be affected.


July 18, 2013 Page 9 of 14

with the Transmission Operator’s step-up transformer tap specifications as identified in Requirement 5.1.


July 18, 2013

Compliance

1. Compliance Monitoring Process:

1.1. Compliance Enforcement Authority:


1.2. Evidence Retention:

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

The Generator Owner shall keep its latest version of documentation on its step-up and auxiliary transformers. The Generator Operator shall maintain all other evidence for the current and previous calendar year.

The Compliance Monitor shall retain any audit data for three years.


As defined in the NERC Rules of Procedure, “Compliance Monitoring and Assessment Processes” refers to the identification of the processes that will be used to evaluate data or information for the purpose of assessing performance or outcomes with the associated reliability standard.

1.4. Additional Compliance Information:

None


July 18, 2013 Page 11 of 14


R # Time Horizon



R1 Real-time Operations

Medium

N/A N/A N/A The responsible entity did not operate each generator in the automatic voltage control mode and failed to notify the Transmission Operator as identified in R1.


Medium N/A N/A N/A The responsible entity did

not perform any of the sub-requirements.


Medium N/A N/A N/A The responsible entity did

not make the notification within 30 minutes.


Lower When directed by the Transmission Operator to maintain the generator voltage or reactive power schedule the Generator Operator failed to meet the directed values for up to and including 45 minutes.

When directed by the Transmission Operator to maintain the generator voltage or reactive power schedule the Generator Operator failed to meet the directed values for more than 45 minutes up to and including 60 minutes.

OR

When a generator’s automatic voltage regulator is out of service, the Generator Operator

When directed by the Transmission Operator to maintain the generator voltage or reactive power schedule the Generator Operator failed to meet the directed values for more than 60 minutes up to and including 75 minutes.

When directed by the Transmission Operator to maintain the generator voltage or reactive power schedule the Generator Operator failed to meet the directed values for more than 75 minutes.

OR

When a generator’s automatic voltage regulator is out of service, the Generator Operator failed to use an alternative method to control the


July 18, 2013 Page 12 of 14

R # Time Horizon



failed to use an alternative method to control the generator voltage and reactive output to meet the voltage or Reactive Power schedule directed by the Transmission Operator.

OR

The Generator Operator failed to provide an explanation of why the voltage schedule could not be met.

generator voltage and reactive output to meet the voltage or Reactive Power schedule directed by the Transmission Operator and the Generator Operator failed to provide an explanation of why the voltage schedule could not be met.


Lower N/A N/A N/A The GOP failed to perform

the tap changes, and the GOP did not provide technical justification for why it cannot comply with the TOP directive


July 18, 2013

Regional Variances

None.

Interpretations

None.

Associated Documents

None.


July 18, 2013 Page 14 of 14


For technical basis for each requirement, please see the VAR White Paper for further technical information.

Compliance Operations Draft Reliability Standard Compliance Guidance for VAR-001 and VAR-002 July 8, 2013 Introduction The NERC Compliance department (Compliance) worked with the Informal VAR Group (IVG) in a review of pro forma VAR-001 and VAR-002 standards. The purpose of the review is to discuss the requirements of the pro forma standards to obtain an understanding of its intended purpose and necessary evidence to support compliance. The purpose of this document is to address specific questions posed by the IVG in order to aid in the wording of the requirements and provide a level of understanding regarding evidentiary support necessary to demonstrate compliance. In addition, a conclusion related to whether the pro forma standards provide reasonable guidance for compliance auditors is provided. However, this document makes no assessment as to the enforceability of the standard. While all testing requires levels of auditor judgment, participating in these reviews allows Compliance to develop training and approaches to support a high level of consistency in audits conducted by the Regional Entities. The following questions will be used to aid in such auditor training. IVG VAR-001 and VAR-002 Questions Question 1 To show that VAR-001 policies or procedures are “implemented,” would Compliance ask for a TOP to provide data around an “event?” Otherwise, would Compliance request TOPs to prove compliance over the entire audit period? What is the best way to provide sample data to support that VAR-001 requirements are being met? Compliance Response to Question 1 (Compliance response in context of VAR-001 R1) Part 1 – Compliance can use a range of approaches to understand and verify implementation. With regard to this standard, those approaches may include observing, interviewing, reviewing an entity’s response to instances of voltage deviation that require operator intervention, as well as reviewing documentation for notifications of voltage deviations that may include exemption requests. Registered entities may also demonstrate the implementation of policies or procedures by providing documentation in connection with an event. Also, auditors may be independently aware of events occurring within the TOP’s area, and the use of such events to determine the nature of an entity’s response is evidence of implementation of policies and procedures. Alternatively, a lack of response to a known event could be evidence of noncompliance with implementation of policies and procedures.

Draft Reliability Standard Compliance Guidance for VAR-001 and VAR-002 July 8, 2013 2

Part 2 – Yes, the Rules of Procedure provide that a registered entity is required to be compliant with Reliability Standards during the audit period. A compliance audit should be appropriately scoped and testing designed to obtain a reasonable assurance of compliance. In this regard, though possible, it is unlikely an auditor would require levels of proof of compliance for an entire audit period and would use approaches such as those noted in Part 1 to gain reasonable assurance of compliance. Part 3 – As noted in the answer to Part 1, there are a range of approaches to help an auditor determine compliance and those range of approaches should be used to help the registered entity demonstrate compliance. As noted above, those approaches may include observing, interviewing, providing documentation relative to an event, as well as documents generated during normal operations such as notifications of voltage deviations. Question 2 For VAR-001 R2, would Compliance focus more on real-time directives? For the day-ahead time frame, is it enough to show studies that were used to schedule resources? Compliance Response to Question 2 Part 1 – Compliance cannot commit to the level of testing that would or would not be performed on a requirement by requirement basis or favoring the testing of one sub-requirement over another. These determinations would be made in connection with the scoping of an audit for a specific registered entity. Part 2 – No. The entity would be expected to provide the documentation for the day ahead scheduling in addition to documentation supporting that it was scheduled, as noted in the requirement. The auditor would first gain an understanding of the entity’s process for conducting the studies and the frequency the studies are performed. Based on the entities response, the auditor most likely would select a sample of studies to verify and ascertain whether the resulting actions, or non actions, were supported by such studies. Documented evidence existing at the time of the study selected by the auditor for verification would be considered stronger evidence than verbal explanations given by entities in response to inquiries during an audit. Question 3 For VAR-001 R3, is the standard clear enough to allow for temporary exemptions? Compliance Response to Question 3 Yes. The TOP would need to provide the criteria and evidence supporting the delivery of the exemption notification.


Question 4 With regard to VAR-002, will generators receive a violation for instances where a system event is affecting system voltage, but the generators made the appropriate conversions and set the AVRs to meet the original schedule provided by the TOP? Compliance Response to Question 4 (Compliance response in context of VAR-002 R2) No, the generator operators can only be responsible for maintaining the schedule provided by the TOP; if the TOP provides a new directive or schedule, the GOP is required to follow the new directive. Question 5 Related to VAR-002, generators monitor voltage on both the low side and high side of the GSU and the “number” being monitored by the Generator will not always equate to the number provided by the TOP. Does this need to be spelled out in the requirement? Compliance Response to Question 5 (Compliance response in context of VAR-002 R2) The Generator should be able to provide documentation that identifies the “number” being monitored and the calculation demonstrating how the “number” equates to the schedule provided by the TOP. Question 6 For VAR-002 R2, the Generator demonstrates compliance by executing the three sub-tasks. Is it clear that those are the only items that a Generator will need to do to maintain voltage? There are events when a unit will be dragged out of voltage schedule, and a unit is limited by its operating capacity to prevent such instances. Those instances should not be a violation under VAR-002 R2, if the GOP is doing everything possible to bring the unit back into a voltage schedule (i.e., the three sub-requirements). Compliance Response to Question 6 The main requirement is clearly stated, that except for an exemption, each of the three sub-requirements must be performed. In this regard, the Generator must document their performance to provide evidence to the auditor of compliance. We have provided additional notes for R2.1-.3 below:

R2.1: Based on the language modification, the Generator may operate up to 30 minutes prior to notifying the TOP that the Generator cannot return to its schedule. The sub-requirement would not require the documentation for instances where a Generator returned to their schedule in 30 minutes or less. Instances greater than 30 minutes would require documentation supporting the Generator contacting the TOP, documentation showing when the Generator first began operating outside of the schedule and when the determination was made the GOP was no longer able to return to its schedule. R2.2: Based on conversations with the IVG, the only alternative is to manually control the reactive

output. In this regard, it is suggested that, unless another method exists, the language be changed to “shall use a manual method.”


R2.3 The sub-requirement is self explanatory and would require the Generator to provide documentation supporting compliance or the written explanation.

Question 7 For VAR-002 requirement R3, the requirement allows for a 15 minute grace-period to reporting a status change, if the issue with reactive resource is corrected. Is that point clear? This requirement is concerned with allowing a Generator to resolve an issue with a resource without having to call or notify the TOP every time the status of the resources goes in and out of service. Also, the IVG would like for telemetered points to count as an automatic notification to the TOP. Is such notification acceptable to Compliance? Compliance Response to Question 7 Part 1 – The Requirement is clear, notification is only required between minutes 16 and 30, regardless of restoration. Part 2 – If telemetered points meet the requirement of a notification, the requirement will need to explain the supporting documentation that substantiates compliance (what evidence can be provided to an auditor.) Conclusion In general, Compliance finds the pro forma standards provide a reasonable level of guidance for Compliance Auditors to conduct audits in a consistent manner. The standard establishes timelines, data requirements, and ownership of specific actions. In general, the standard would provide reasonable guidance to develop training for Compliance Auditors to execute their reviews. Compliance does recommend the IVG address the issues noted in the previous section of this document related to the standards.

Following final approval of the Reliability Standard, Compliance will develop the final Reliability Standards Auditor Worksheet (RSAW) and associated training.

Implementation Plan VAR Directives Project

Implementation Plan for VAR-001 and VAR-002

Approvals Required VAR-001-4 – Voltage and Reactive Control VAR-002-3 — Generator Operation for Maintaining Network Voltage Schedules


Revisions to Glossary Terms None

Applicable Entities

Generator Operators

Generator Owners

Transmission Operators

Reliability Coordinators Applicable Facilities N/A Conforming Changes to Other Standards None Effective Dates VAR-001-4 and VAR-002-3 - In those jurisdictions where regulatory approval is required, this standard shall become effective on the first day of the first calendar quarter after applicable regulatory approval or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities. In those jurisdictions where no regulatory approval is required, this standard shall become effective on the first day of the first calendar quarter after Board of Trustees approval.

Project 2012-05 ATC Revisions Implementation Plan June 27, 2013

2

Justification The currently effective VAR-002 standard is one of the most violated standards; however, the industry argues these violations do not address any reliability gaps. Instead, Generator Operators and Transmission Operators are required to handle many nuisance phone calls for slight deviations from a voltage schedule. The nuisance phone calls can be a distraction during a scheduled maintenance or a system event; thus, the industry would support making the changes as soon as possible. However, since VAR-001 now requires a documented policy or procedure for assessments; the Transmission Operators need a quarter to prepare documentation. Also for Transmission Operators that do not provide tolerance bands with voltage schedules, those Transmission Operators will need some time to adjust to providing new data to Generator Operators. Retirements VAR-001-3 and VAR-002-2b will be retired at midnight of the day immediately prior to the Effective Date of VAR-001-4 and VAR-002-3 in the particular Jurisdiction in which the new standards are becoming effective.

VAR Mapping Document Transition of VAR-001-3 and VAR-002-2b (the pro forma standard)

Standard: VAR-001-4 – Voltage and Reactive Control Requirement in



VAR-001-3 R1 Requirement R1

The pro forma creates adds additional sub-requirements that requires the policies and procedures to include criteria for system assessments. The assessments must now include steady-state limits, voltage stability limits and associated operating margins, and voltage schedules along with associated tolerance bands. The sub-requirements also now mandate that information is shared with neighboring TOPs and the applicable RC.

VAR-001-3 R2 Requirement R2 The new requirement has been updated to incorporate real-time and day-ahead scheduling of resources. It eliminates the need for the existing R7, R8, and R9.


The new requirement has been simplified by removing the need to maintain an exemption list. Instead, the standard focuses on whether the exemption criteria are known and whether a granted exemption was communicated to the applicable Generator.

VAR Revisions

2

Standard: VAR-001-4 – Voltage and Reactive Control Requirement in




The new requirements have been updated to allow the TOP to provide the voltage or Reactive Power schedule at either the high side or the low side of the GSU. Also as tolerance band is now required under the new requirement.

VAR-001-3 R5 Deleted Pending a final rulemaking on P81, this requirement has been deleted.

VAR-001-3 R6 Requirement R5 The sub-requirement R6.1 was deleted because it is duplicative of VAR-002’s requirement R1 and R2.

VAR-001-3 R7 Deleted See comments for new R2. VAR-001-3 R8 Deleted See comments for new R2. VAR-001-3 R9 Deleted See comments for new R2. VAR-001-3 R10 Deleted This is duplicative of TOP-001-2 and the Tv definition. VAR-001-3 R11 Requirement R6 The only change is the numbering due to other deletions.

VAR-001-3 R12 Deleted

This requirement was deleted because the EOP standards address taking any corrective action including load-shedding. Also the new TOP-002-3 R2 and TOP-001-2 R11 address the TOP taking corrective actions.

Standard: VAR-002-3 – Capacity Benefit Margin Requirement in



VAR-002-2b R1 Requirement R1 The requirement has not been modified.

VAR Revisions

3

Standard: VAR-002-3 – Capacity Benefit Margin Requirement in



VAR-002-2b R2 Requirement R2 The new pro forma requirement has been updated by including a new sub-requirement to allowing GOPs to only call in certain instances when deviating from voltage schedules .

VAR-002-2b R2 Requirement R3 The new pro forma requirement has been updated by including a new sub-requirement to allowing GOPs to investigate why the status has changed on AVR equipment before having to notify the TOP.

VAR-002-2b R2 Requirement R4 The requirement has not been modified. VAR-002-2b R2 Requirement R5 The requirement has not been modified.

NERC | VAR White Paper | July 18, 2013 1 of 19

White Paper on the VAR Standards VAR-001 and VAR-002

July 18, 2013




Table of Contents Table of Contents ......................................................................................................................................................................... 2 Executive Summary ..................................................................................................................................................................... 3 Purpose ........................................................................................................................................................................................ 5 History of the VAR Informal Development .................................................................................................................................. 6 Technical Discussion .................................................................................................................................................................... 7

Background .............................................................................................................................................................................. 7

VAR-001 ................................................................................................................................................................................... 7

VAR-002 ................................................................................................................................................................................... 8

Outstanding FERC Directives ..................................................................................................................................................... 11 Directive from P 1855 of Order No. 693 ................................................................................................................................ 11

Directive from P 1858 of Order No. 693 ................................................................................................................................ 11








Conclusion ................................................................................................................................................................................. 17 Entity Participants ...................................................................................................................................................................... 18


Executive Summary The VAR Reliability Standards provide the minimum requirements for maintaining voltage stability on the bulk-power system. The industry considers VAR-001 to represent transmission requirements for monitoring the reactive power performance of the system, and VAR-002 represents generator obligations for voltage support. When the VAR standards were initially approved by the Federal Energy Regulatory Commission (“FERC” or the “Commission”) in 2006, the Commission provided several directives on how to improve the VAR standards. NERC initiated Project 2008-01 to address these FERC directives, but that project was unable to be completed due to a project reprioritization. Project 2008-01 and its Standard Authorization Request (SAR) used a prescriptive approach to address the FERC directives, and that project also contemplated adding an additional planning standard. This project took a different approach by implementing the Paragraph 811

and results-based standards initiatives. This project also utilized the recommendations from a panel of Independent Experts’ Review of the NERC Reliability Standards. Due to this variance in approach, the informal development group is presenting a new SAR to post for industry comment.

In summary, FERC gave the following directives to modify VAR-001: • Expand the applicability to include Reliability Coordinators (RCs) and load-serving entities (LSEs). • Include detailed and definitive requirements on “established limits” and “sufficient reactive resources” and

identify acceptable margins above the voltage instability points. • To assist real-time operations for areas susceptible to voltage instability, include requirements to perform voltage

stability analysis periodically, using online techniques where commercially available and offline techniques where online techniques are not available.

• Include controllable load among the reactive resources to satisfy reactive requirements. • Address the power factor range at the interface between LSEs and the transmission grid.

FERC directed NERC to consider modifying VAR-002 to require more detailed and definitive requirements when defining the time frame associated with an “incident” of noncompliance. Hence, FERC directed NERC to consider a timeframe for allowing a generator to be out of schedule before having to make a notification to its TOP. In early 2013, NERC initiated an informal development project to address the directives, and an informal development group was formed from industry subject matter experts, NERC staff, and staff from FERC’s Office of Electric Regulation. The informal development group sought to answer FERC’s directives and improve some of the compliance issues that exist today for the VAR standards. The informal development group drafted several pro forma versions of the VAR standard and sought broad industry feedback through individual phone conversations, conference calls, technical conferences, and webinars. Since 2006, many changes have occurred that impact the VAR standards. Several new standards have been drafted and approved in the last seven years. Also, FERC recently issued a Notice of Proposed Rulemaking (NOPR) addressing Paragraph 81, and that NOPR recommends retiring certain VAR requirements that are redundant with Open-Access Transmission Tariffs (OATTs). In addition, VAR-002 has consistently been identified as one of the most violated standards, so certain compliance issues surround VAR-002 had to be addressed. In concert with the Paragraph 81 initiative, each of the above-mentioned directives does not equate to a new VAR requirement. Instead, the informal development group removed certain redundancies with other standards and created requirements that provide for documented policies and procedures to address the above directives for VAR-001. The pro forma VAR-001 has added RC monitoring requirements, and the standard requires each Transmission Operator (TOP) to have written operating policies and procedures used to define voltage limits. Those policies and procedures must set definitive guidelines on the frequency of system assessments. Further, the pro forma standard states that controllable load is a viable reactive power resource that can be used in the day-ahead and real-time operations. The informal development project did not address power factor, because the relevant requirement that currently addresses LSEs and

1 See North American Electric Reliability Corp., 138 FERC ¶ 61,193, at P 81, order on reh’g and clarification, 139 FERC ¶ 61,168 (2012).

Executive Summary


power factor is proposed for retirement by FERC in its June 2013 NOPR on Paragraph 81 because the OATT covers the arrangement for ancillary services that include VAR purchases to maintain power factor. Additionally, VAR-002 has been amended in the pro forma standard to provide for a noncompliance timeframe when a generator is out of voltage schedule and when reactive power equipment is out-of-service and then back in-service status again. The language not only addresses FERC’s directive, but it also provides resolution to several compliance issues in existence today. Certain timing elements for VAR-002 may be debated during the formal development process, but the informal development group has reached a consensus on the principles of providing these time periods. As detailed further below, the informal development group drafted the pro forma VAR standard in a manner that would accomplish three objectives: 1) address the FERC directives; 2) mitigate compliance issues for generators in VAR-002; and 3) simplify the TOP’s requirements in VAR-001 while maintaining reliability and eliminating nuisance phone calls. The pro forma standard is not overly prescriptive, and Compliance has prepared guidance that will develop into RSAWs and auditor training. This guidance will allow for more predictability when the new VAR standard is implemented, and it will hopefully alleviate some industry concerns regarding future audits.

Purpose


Purpose The purpose of this white paper is to provide a summary of the issues, rationale, and support for the proposed revisions to the currently enforceable VAR standards, VAR-001 and VAR-002. This white paper also provides an explanation of how outstanding VAR directives from the Commission contained in Order No. 6932

are addressed going forward. This white paper is a product of the informal development process, which provides for the formation of an informal development group. The informal development group met several times and conducted numerous webinars and technical conferences from February through June 2013. The information obtained through industry outreach was discussed thoroughly by the informal development group, and several of the discussion topics are reflected throughout this paper. In addition, the contents of this paper will give a foundation to the formal development process.

The ultimate goal of the Standards team is present the new VAR standards to the Board of Trustees in their November 2013 meeting. Thus, the formal Standards Drafting Team will be seeking final industry approval of the VAR standards by October 2013.

2 See Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC Stats. & Regs. ¶ 31,242, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007).

History of the VAR Informal Development


History of the VAR Informal Development The informal development group started with a group of individuals that were originally part of Project 2008-01. Due to a project reprioritization conducted by the Standards Committee and NERC, Project 2008-01 was halted. There is some overlap between the current VAR project and project 2008-01, but the scope is slightly different. Project 2008-01 was moving toward creating a VAR planning standard in addition to modifying VAR-001 and VAR-002. The current project is only amending VAR-001 and VAR-002, and the current project remains predominantly focused on addressing the outstanding FERC directives. The informal development group first met on a February 15, 2013 conference call. The meeting was to introduce the various parties and a coordinate logistics for the informal development process. The informal development group is currently comprised of the following:

• Dennis Chastain – Tennessee Valley Authority • Bill Harm – PJM Interconnection L.L.C. • Steve Hitchens – Bonneville Power Administration • Sharma Kolluri – Entergy Services Inc. • Martin Kaufman – ExxonMobil Research and Engineering Company • Joshua Pierce – Southern Company • Hari Singh – Xcel Energy • Hamid Zakery – Calpine Corporation • Scott Berry – Indiana Municipal Power Agency

Members of the informal development group met in person on February 27 and 28 in Atlanta. The group then convened several times over conference calls before an April 11 webinar. The April 11 webinar was the first time the group proposed new VAR language to address a majority of the directives from Order No. 693. The industry provided significant feedback during two subsequent technical conferences. The first technical conference was hosted by Southern Company in Atlanta, Georgia, on April 18, 2013. The second technical conference was held at Xcel Energy in Denver, Colorado, on April 29, 2013. Both conferences provided an opportunity for the informal development group to listen to industry concerns regarding the VAR standards, and the informal development group answered numerous questions on the current draft of the pro forma standards. The informal development group reconvened for a two-day meeting at Entergy on May 15, 2013. The group also invited several individuals who participated in the webinars and technical conferences to attend the meeting. During the May meeting, the VAR pro forma standard was modified several times. The informal development group continued the discussion on how to best address industry’s concerns through electronic communications and several conference calls. The next iteration of the pro forma standard was then presented to the industry on a June 14 webinar. The webinar contained several survey questions, and the informal development group was able to gauge whether a majority of industry supported the pro forma standard. Based on the survey and webinar feedback, the informal development group was able to amend the pro forma standard further before presenting the final draft to the Standards Committee on July 18, 2013.



Technical Discussion Background What is Reactive Power? Reactive power does not have the same characteristics as real power. Real power is measured in watts and able to be transmitted over long distances. Real power is an energy supply that is eventually distributed to end-use customers. Reactive power is just as important as real power because it is necessary to maintain system stability. Reactive power supports voltage. Voltage is measured in volts, and electrical current is measured in amperes. Reactive power is measured in volt-amperes reactive (VARs). When the Bulk Electric System (BES) does not have enough reactive power, there is risk of a voltage collapse, which could lead to cascading outages. In fact, a lack of reactive power supply was a contributing factor to the large blackouts in 2003 and 2011. Nature of Reactive Power and Why it is Necessary Generally reactive power is needed to provide voltage support and maintain system stability. Prabha Kundur, a leading subject matter expert in system stability, explains, “[p]ower system stability may be broadly defined as that property of a power system that enables it to remain in a state of operating equilibrium under normal operating conditions and to regain an acceptable state of equilibrium after being subjected to a disturbance.”3

The VAR standards ensure that there is enough reactive power on the system to provide the voltage support necessary to avoid voltage collapse. Although there are numerous reactive power resources, the best and largest source of reactive power or VAR support comes from generators. However, the amount of reactive power that a generator can create is proportional to the amount of MWs being produced. Therefore, the more VARs produced at a generating facility, the fewer MWs produced.

VAR-001 The stated purpose of the VAR-001 standard is to ensure that voltage levels, reactive flows, and reactive resources are monitored, controlled, and maintained within limits in real time to protect equipment and the reliable operation of the interconnection. The VAR standards focus on the Operations horizon (which is real-time up to one year into the future). The informal development group is cognizant of the fact that the nature of reactive power on the network varies depending on local conditions. Thus, the group focused on the process that the requirements would detail, not the proper numbers a TOP should enforce in the standard. For VAR-001, the group would not put operational limits on how a TOP should manage voltage stability for its regions; more specifically, the informal development group did not want to place numerical requirements on what the proper operational limits should be for the continent. Operating margins vary due to specific system characteristics as well as the operating conditions. Rather than detailing a continent-wide back-off margin, the informal development group designed the pro forma VAR-001 to require the Transmission Operator to document policies and procedures used to establish, monitor, and control voltage and reactive power flows (Mvars). Those policies are then used to establish voltage and reactive power schedules for the generators. Requirement R1 R1 requires that documented policies and procedures are in place. These policies and procedures must include criteria for the assessments of the TOP’s systems. The policies will consequently include studies used to establish voltage schedules and associated tolerance bands. In addition, the system assessments must include dynamic voltage limits and operating margins. By requiring a documented policy and procedure, the reliability standard removes the opportunity for auditors or other parties to scrutinize a TOP’s own system studies. R1 also requires Transmission Operators to communicate their policies and procedures with their associated RC and neighboring TOPs. This type of communication relates to R2, which details how a TOP and RC take a system study and ensure sufficient reactive power is available to support both real-time and day-ahead operations. Requirement R2

3 Prabha Kundur, Power System Stability and Control, Electric Power Research Institute, p. 17 (1994).



R2 requires both TOPs and RCs to perform system assessments in order to schedule reactive resources for both the real-time and day-ahead time frames. By scheduling sufficient reactive resources, the TOP and RC are maintaining voltage levels (and consequently system stability) under both normal and contingency situation. R2 further defines “sufficient reactive resources,” and those resources include controllable load pursuant to FERC Order No. 693. Requirement R3 R3 requires each TOP to specify what criteria will exempt a generator from 1) having to follow a provided voltage schedule; or 2) providing a notification under VAR-002. The TOP must notify the generator when an exemption is given, but there are no requirements on what the criteria should be for exemptions. This enables TOPs to have flexibility when providing exemptions during maintenance or system events. For example, if a unit is experiencing a malfunction in AVR equipment, the TOP may provide a temporary exemption to the generator until the equipment is repaired. Requirement R4 R4 requires each TOP to specify a voltage or reactive power schedule and associated tolerance band for each generator. By requiring both a tolerance band and a documented policy or procedure for establishing voltage schedules, there is a level of transparency as to how voltage or reactive power schedules were created. The informal development group refrained from providing any language that requires GOPs to mutually agree with TOPs on specific numbers. Such language could create disputes between the parties as to what the appropriate voltage schedule should be for a unit. To preserve a TOP’s ability to assess and monitor its system, and in an effort not to undermine the TOP standards, R4 provides more transparency while clearly maintaining a TOP’s role in determining voltage schedules. Requirement R5 R5 ensures that the TOP knows the status of all reactive power resources, automatic voltage regulators, and power system stabilizers in its system. This requirement mandates that the TOP actively monitor the system for voltage issues, and the new measure language now specifies that electronically metered points and EMS data will serve as a compliance mechanism for this particular requirement. Requirement R6 The informal development group did not modify the requirement regarding step-up transformer tap changes. WECC Variance FERC approved the WECC variance to VAR-001 on June 20, 2013.4 The WECC variance eliminates the TOP’s ability to allow for exemptions, and it also requires a TOP to (1) issue a choice of voltage schedules for each of the generating resources that are on-line and part of the BES in its area; (2) provide to Generator Operators (GOPs) a voltage schedule reference point; and (3) provide transmission equipment data and operating data requested by GOPs to support their set point conversion methodology.5

The informal development group did not adopt the WECC variance because it is more stringent than the existing standard, and numerous TOPs want the flexibility to allow for exemptions from notification requirements, particularly when maintenance is being performed or when a generator’s AVR is malfunctioning. However, the current pro forma standard does not affect the WECC variance. Since the WECC variance is retained, the VAR-001 standard is applicable to GOPs in the WECC region.

VAR-002 The purpose behind the VAR-002 standard is for generators to 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. Currently, VAR-002 is problematic due the numerous violations for GOPs 1) when a unit deviates from schedule; and 2) when an AVR turns on, then off. In both instances, a generator has an obligation under the currently enforceable standard to call a TOP within 30 minutes. The current standard does not allow for any deviations from notification requirements; thus, the GOP must determine if it is more appropriate to make a notification or address a potential issue that is affecting the voltage schedule or AVR status. The notifications themselves also create “nuisance” phone calls for TOPs. Most TOPs have the ability to monitor voltage through telemeter equipment.

4 See Petition for Approval of Proposed Reliability Standard VAR-001-3 (WECC Variance), Letter Order, Docket No. RD13-6-000 (issued June 20, 2013). 5 See VAR-001-3



Thus, most TOPs already know when a unit drifts out of schedule. In order to address both the compliance issues and FERC’s directive to consider a noncompliance window, the pro forma VAR-002 proposes language that gives a GOP time to respond to an issue before notifying its TOP. Requirement R2 R2 requires GOPs to follow a TOP-provided voltage or reactive power schedule. However, there is universal agreement among TOPs and GOPs that if a unit drifts out of schedule momentarily and then drifts back into schedule, there is no risk to the reliability of the system. However, under the current VAR-002 standard in effect, when a unit drifts out of schedule there is an obligation to notify the TOP. Also, when the unit goes back into schedule there is an obligation to notify the TOP again. Thus, for a slight deviation, a GOP may face two potential violations for failure to make notifications to the TOP. Based on industry feedback, a TOP should be notified when a unit cannot follow a voltage schedule. However, notifications for every schedule change are harmful to reliability because such calls detract focus from addressing system issues as they occur. The new language in the pro forma standard for R2 requires a GOP to notify a TOP when 1) the unit has been out of schedule for 15 minutes; AND 2) when a unit cannot return to schedule. In most cases, a unit will not be able to return to schedule when it has encountered an operating limit. There are also instances when a system event is pulling the unit out of schedule, and the unit is too small to move its voltage back in schedule. In these situations, it is important for the TOP to be notified, because those units cannot provide anymore voltage support to combat a system event. Requirement R3 R3 requires a GOP to notify its TOP within 30 minutes of a “status” change. The status change identifies whether a reactive resource is available for voltage support. In an effort to allow GOP to first identify and address why a status change has occurred, the new pro forma standard Requirement R3 gives the GOP an initial 15 minutes to correct and restore the status of any reactive power resource. However, if the status has not been corrected after 15 minutes, the GOP has 15 minutes to notify its associated TOP of the status change. Requirements R1, R4, and R5 The informal development group did not modify the requirement regarding AVR and tap changes. Monitoring Both R2 and R3 inherently have several compliance issues with regard to how voltage is monitored and controlled. Most TOPs provide GOPs with a voltage schedule as the high side of the generator step-up transformer, but a large number of GOPs only have metering equipment on the low side of the transformer. Therefore, in order to meet a voltage schedule, but these GOPs will convert the “high-side” schedule to a “low-side” schedule. The low-side schedule is then usually translated into an AVR control point or target. However, for several smaller facilities and nuclear facilities, those generators have installed metering on the high-side. Also, some facilities have made additions to their facilities to add load-drop compensation to see monitoring on the high-side. Thus, although many Generators monitor voltage on the low side of the terminal, there are a significant number of facilities that monitor voltage on the high side. Generators that use high-side voltage reference for regulation receive voltage reference signals from their associated TOP. This can create an issue during audits, because the standard does not dictate which method is acceptable for monitoring voltage. In order to develop a continent-wide standard that allows GOPs to monitor voltage based on existing equipment limitations, the language of pro forma VAR-002’s measures was greatly augmented. Specifically, the GOPs were explicitly given the discretion to monitor on either the high side or low side of the transformer. The pertinent language added to M2 is, “[i]n order to identify when a unit is deviating from its schedule, GOPs will monitor voltage based on existing equipment at its facility. Therefore, GOPs have the option to operate on a voltage schedule on the high side or convert the high-side schedule to a low-side schedule at the GOP’s discretion.” This language is necessary to assure GOPs that the standard will not determine where specific equipment should be installed at a facility. Further, this language clarifies to an auditor that either high-side or low-side monitoring is sufficient for VAR-002 compliance. AVR Once the AVR is set and in “voltage controlling” mode, the AVR should automatically adjust to voltage swings. At issue is whether a generator is required to make any adjustments to a control-point or AVR setting when the AVR response is not enough to react to a voltage deviation or system event. There is a current debate in the industry as to what actions are



required to maintain system stability. From the Generator’s perspective, the AVR is the best mechanism to address voltage, and several Generators advocate that if an AVR setting should be adjusted, then the respective TOP should direct that AVR change. The TOPs argue that if an event is occurring, there is not enough time to call each generator to dictate the specifications for an adjustment; further, the TOPs assert that generators have an obligation to maintain a voltage schedule that includes making the necessary AVR adjustments. This industry divide is not addressed in the pro forma standard presented today. The informal development group did not address changing underlying principles of the VAR-002 standard, because the scope of the project with regard to VAR-002 was merely to consider a non-compliance window. However, the issue may be revisited during the formal development stage by the standard development team.


Outstanding FERC Directives The VAR standards were first approved in FERC Order No. 693.6

However, in approving the standards, the Commission also gave several directives on how to improve the VAR standards for reliability purposes. VAR-001 targets the transmission responsibilities for maintaining voltage stability while VAR-002 focuses on generator functions. Order No. 693 summarized the directives for VAR-001 as requiring NERC to do the following:

(1) expand the applicability to include RCs and LSEs; (2) include detailed and definitive requirements on “established limits” and “sufficient reactive resources” as discussed above, and identify acceptable margins above the voltage instability points; (3) to assist real-time operations for areas susceptible to voltage instability include requirements to perform voltage stability analysis periodically, using online techniques where commercially available and offline techniques where online techniques are not available; (4) include controllable load among the reactive resources to satisfy reactive requirements; and (5) address the power factor range at the interface between LSEs and the transmission grid.7

For VAR-002, FERC directed NERC to consider providing more definitive requirements on what a noncompliance window should be for mandatory notifications. Each of the relevant directives is explained in further detail below.

Directive from P 1855 of Order No. 693 “Accordingly, the ERO should modify VAR-001-1 to include reliability coordinators as applicable entities and include a new requirement(s) that identifies the reliability coordinator’s monitoring responsibilities.”

VAR Informal Consideration The informal development group amended VAR-001 to make RCs applicable to this standard, and requirements were added that identify RC monitoring for voltage stability. The informal development group did not expand the VAR standards to be overly prescriptive with regard to how an RC should monitor its own system; further, the group did not want to duplicate the efforts of the IRO standards pending before FERC. Instead the group focused on the most critical elements necessary for an RC to monitor its system for voltage stability. An RC performs many monitoring functions, but for voltage stability it is necessary to ensure that 1) the RC is aware of how its TOPs are monitoring voltage, and 2) the RC is performing the adequate studies to ensure reactive resources are properly scheduled for both real-time and day-ahead operations. Although some entities in Texas provided feedback that certain RCs perform functions equivalent to a TOP, the informal development group did not expand VAR-001 to give parity to TOPs and RCs. Upon further investigation, these situations are addressed through contractual obligations that clearly outline the reliability roles of both parties. The new RC functions are reflected in the new VAR pro forma standard through requirements R1 and R2. Both requirements are detailed further below.

Directive from P 1858 of Order No. 693 “The Commission directs the ERO to address the reactive power requirements for LSEs on a comparable basis with purchasing-selling entities.” VAR Informal Consideration This FERC directive was addressed in VAR-001-2.8 The Commission also recently issued a NOPR regarding Paragraph 81 that recommended retiring the existing VAR requirement that initially answered FERC’s directive in P 1858.9

FERC’s support for Paragraph 81 and rationale for proposing the retirement is:

6 See generally, Order No. 693 at PP 1846-1885. 7 Order No. 693 at P 1880. 8 See FERC letter order, NERC Petition for Approval of Proposed Modifications to Reliability Standards BAL-002-1; EOP-002-3; FAC-002-1; MOD-021-2; PRC-004-2; and VAR-001-2, 134 FERC ¶ 61,015 (2011). 9 See Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, Notice of Proposed Rulemaking, 143 FERC ¶ 61,251 (2013) (“NOPR”).



We propose to approve the retirement of VAR-001-2, Requirement R5 based on NERC’s assertion that Requirement R5 is redundant with provisions of the pro forma OATT. Specifically, Schedule 2 of the open access transmission tariff requires transmission providers to provide reactive power resources, either directly or indirectly, and requires transmission customers to either purchase or self-supply reactive power resources.10

In light of this NOPR, the informal development group is not adding new language to the VAR standard that would address this directive. Further, there is an ongoing NERC effort to evaluate if purchasing-selling entities (PSEs) should continue to be a registered function. The informal development group may address this directive in the future, pending a final rulemaking from FERC and a determination on the status of the future applicability of standards to PSEs.

Directive from P 1861 of Order No. 693 “In the NOPR, the Commission asked for comments on acceptable ranges of net power factor at the interface at which the LSEs receive service from the Bulk-Power System during normal and extreme load conditions... The Commission believes that Reliability Standard VAR-001-1 is an appropriate place for the ERO to take steps to address these concerns by setting out requirements for transmission owners and LSEs to maintain an appropriate power factor range at their interface. We direct the ERO to develop appropriate modifications to this Reliability Standard to address the power factor range at the interface between LSEs and the Bulk- Power System.” VAR Informal Consideration Initially, the informal development group addressed the directive on power factor in two ways. First, based on P 1863,11 the informal development group considered requiring seasonal power factor data to be provided to the TOPs on request. This would ensure the system studies were based on accurate data. Second, the informal development group considered whether entities could ensure power factor is maintained by arranging for VARs when MWs are purchased. However, the recently issued NOPR recommends retiring the requirement that currently requires VARs to be acquired due to redundancy with OATT. The NOPR also recommends withdrawing P 1863 as a directive because the Commission clarified the paragraph to be general guidance, not a FERC directive to modify the standard.12

In addition, the informal development group did not further amend the pro forma standard to add obligations to maintain power factors, because the FAC-001 standard requires Transmission Owners (TOs) to set interconnection requirements including “Voltage, Reactive Power, and power factor control.”13 Interconnection agreements also define minimum power factor requirements as a contractual obligation.14 In an effort to keep the VAR standard consistent with interconnection requirements established by contract, and consistent with the pro forma Generator Interconnection agreements pursuant to FERC Order No. 2003 which requires a 0.95 leading to 0.95 lagging power factor,15

the informal group did not add any additional requirements at this time to address power factor.

Directive from P 1862 of Order No. 693 “We direct the ERO to include APPA’s concern in the Reliability Standards development process. We note that transmission operators currently have access to data through their energy management systems to determine a range of

10 NOPR at P 83. 11 Order No. 693 at P 1863 (stating “[t]he Commission expects that the appropriate power factor range developed for the interface between the bulk electric system and the LSE from VAR-001-1 would be used as an input to the transmission and operations planning Reliability Standards”). 12 See NOPR at Attachment A. 13 See FAC-001-0, R 2.1.9. (available at: http://www.nerc.com/files/FAC-001-0.pdf) (emphasis added). 14 See, e.g., Standardization of Generator Interconnection Agreements and Procedures, Order No. 2003, FERC Stats. & Regs. ¶ 31,146 (2003), order on reh’g, Order No. 2003- A, FERC Stats. & Regs. ¶ 31,160, order on reh’g, Order No. 2003-B, FERC Stats. &Regs. ¶ 31,171 (2004), order on reh’g, Order No. 2003-C, FERC Stats. & Regs. ¶ 31,190 (2005), aff’d sub nom. Nat'l Ass’n of Regulatory Util. Comm’rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007), cert. denied, 552 U.S. 1230 (2008) (establishing Large Generator Interconnection Agreement requirement). 15 Order No. 2003 at P 542 (finding “[w]e adopt the power factor requirement of 0.95 leading to 0.95 lagging because it is a common practice in some NERC regions. If a Transmission Provider wants to adopt a different power factor requirement, Final Rule LGIA Article 9.6.1 permits it to do so as long as the power factor requirement applies to all generators on a comparable basis”).

http://www.nerc.com/files/FAC-001-0.pdf�



power factors at which load operates during various conditions, and we suggest that the ERO use this type of data as a starting point for developing this modification.” VAR Informal Consideration APPA stated, “It may be difficult to reach an agreement on acceptable ranges of net power factors at the interfaces where LSEs receive service from the Bulk-Power System because the acceptable range of power factors at any particular point on the electrical system varies based on many location-specific factors. APPA further states that system power factors will be affected by the transmission infrastructure used to supply the load.”16

APPA’s concerns were discussed, and the informal development group did not want to establish a particular range on power factor, especially since power factor requirements are detailed in interconnection agreements as discussed with the P 1861 directive.

Directive from P 1868 of Order No. 693 “In the NOPR, the Commission expressed concern that the technical requirements containing terms such as “established limits” or “sufficient reactive resources” are not definitive enough to address voltage instability and ensure reliable operations. To address this concern, the NOPR proposed directing the ERO to modify VAR-001-1 to include more detailed and definitive requirements on “established limits” and “sufficient reactive resources” and identify acceptable margins (i.e. voltage and/or reactive power margins) above voltage instability points to prevent voltage instability and to ensure reliable operations. We will keep this direction, and direct the ERO to include this modification in this Reliability Standard.”

Directive from P 1869 of Order No. 693 We recognize that our proposed modification does not identify what definitive requirements the Reliability Standard should use for “established limits” and “sufficient reactive resources.” Rather, the ERO should develop appropriate requirements that address the Commission’s concerns through the ERO Reliability Standards development process. The Commission believes that the concerns of Dynegy, EEI and MISO are best addressed by the ERO in the Reliability Standards development process. VAR Informal Consideration for PP 1868 and 1869. In an effort to address this directive and in order to preserve the TOs’ flexibility to monitor their systems accordingly, the informal development group added requirements in the pro forma standard VAR-001 Requirement R1 that require steady-state and voltage limits to be included in the criteria used to assess transmission systems:

R1. Each Transmission Operator shall have documented policies or procedures that are implemented to establish, monitor, and control voltage levels and Reactive Power flows (Mvar flows) within limits as defined below:

R. 1.1. These documented policies or procedures shall include criteria used in system assessments. The criteria for the assessments shall include established steady-state and voltage stability limits with associated tolerance bands and operating margins.

Also, a new Requirement R2 was updated to include existing language on reactive resources that a TOP can schedule in both the real-time and day-ahead time frame. That list of sufficient reactive resources includes reactive generation scheduling, transmission line and reactive resource switching, and controllable load.

Directive from P 1875 of Order No. 693 In response to the concerns of APPA, SDG&E and EEI on the availability of tools, the Commission recognizes that transient voltage stability analysis is often conducted as an offline study, and that steady-state voltage stability analysis can be done online. The Commission clarifies that it does not wish to require anyone to use tools that are not validated for real-time operations. Taking these comments into consideration, the Commission clarifies its proposed modification from the NOPR. For the Final Rule, we direct the ERO, through its Reliability Standards development process, to modify Reliability Standard VAR-001-1 to include Requirements to perform voltage stability analysis periodically, using online techniques where commercially-available, and offline simulation tools where online tools are not available, to assist real-time

16 Order No. 693 at P 1860.



operations. The ERO should consider the available technologies and software as it develops this modification to VAR-001-1 and identify a process to assure that the Reliability Standard is not limiting the application of validated software or other tools. VAR Informal Consideration The informal group determined that the Commission is not requiring TOPs to purchase new online models or to implement tools that will not adequately study a TOP’s reactive power requirements. Instead, the group allowed the TOPs to create their own documented procedures for performing assessments in pro forma standard Requirement R1. Further, TOPs may under the new pro forma standard align their voltage planning with the pending TPL standards currently being reviewed by the Commission. The TPL standards require voltage studies, as outlined below:

R5. Each Transmission Planner and Planning Coordinator shall have criteria for acceptable System steady-state voltage limits, post-Contingency voltage deviations, and the transient voltage response for its System. For transient voltage response, the criteria shall at a minimum specify a low voltage level and a maximum length of time that transient voltages may remain below that level. 17

Directive from P 1879 of Order No. 693 The Commission noted in the NOPR that in many cases, load response and demand-side investment can reduce the need for reactive power capability in the system. Based on this assertion, the Commission proposed to direct the ERO to include controllable load among the reactive resources to satisfy reactive requirements for incorporation into Reliability Standard VAR-001-1. While we affirm this requirement, we expect the ERO to consider the comments of SoCal Edison with regard to reliability and SMA in its process for developing the technical capability requirements for using controllable load as a reactive resource in the applicable Reliability Standards. VAR Informal Consideration NERC addressed this directive in a prior version of the VAR standard,18

but as mentioned above, the list for sufficient reactive resources that includes controllable load has been retained in R2.

Directive from P 1885 of Order No. 693 “Dynegy has suggested an improvement to Reliability Standard VAR-002-1, and NERC should consider this in its Reliability Standards development process.” Dynegy requested that VAR-002 be modified to include “more detailed and definitive requirements when defining the time frame associated with an ‘incident‘of non compliance.”19

VAR Informal Consideration The informal development team addressed this directive in two separate requirements. The noncompliance incidences at issue occur 1) when a generator deviates from a voltage or reactive power schedule; and 2) when a generator is not operating a unit in automatic voltage control mode; more specifically, automatic voltage regulator (AVR) should be in service and controlling voltage. The new pro forma VAR-002 R2.1 addresses when a unit must notify its TOP when a unit is out of schedule:

R.2.1. If a GOP drifts out of schedule, each Generator Operator shall notify its associated Transmission Operator within 15 minutes when both of the following conditions are met: 1) the GOP is operating outside of the prescribed voltage or

17 SeeTPL-001-2, R5 (available at http://www.nerc.com/files/TPL-001-2.pdf). 18 See NERC Petition for Approval of Proposed Modifications to Reliability Standards BAL-002-1; EOP-002-3; FAC-002-1; MOD-021-2; PRC-004-2; and VAR-001-2, 134 FERC ¶ 61,015 (2011). 19 Order No. 693 at P 1883.



Reactive Power schedule tolerance band20

for 15 minutes; and 2) the GOP is no longer able to return to its voltage or Reactive Power schedule.

The new pro forma VAR-002 R3 addresses when a unit must contact its TOP when the facility is out of AVR:

R3. Each Generator Operator shall notify its associated Transmission Operator of a status or capability change on any generator Reactive Power resource, including the status of each automatic voltage regulator and power system stabilizer and the expected duration of the change in status or capability within 30 minutes of the change. If the status has been restored within the first 15 minutes of such change, then there is no need to call TOP.

The informal development group established the 15-minute time requirements following much discussion. Several industry stakeholders advocated for a larger window of time before a notification must be made; however, there is no consensus on when a reliability gap would be created by expanding the time requirements. Some stakeholders also argued that 15 minutes was excessive.

20 GOPs monitor and control voltage based on their equipment limitations. GOPs will monitor their voltage or Reactive Power schedule tolerance bands either at the high-side or low-side/terminal voltage.


Conclusion The goal of the VAR informal development project is to provide a venue for addressing many of the issues that can arise during the formal development process. By engaging with industry stakeholders through an active dialogue, the informal development group was able to efficiently address the concerns of many entities through conference calls, webinars, and informal group meetings. The informal group collaborated over the past five months to develop robust pro forma VAR standards that will serve as the basis for a new VAR standard, which should be posted for industry comment in August 2013. This white paper serves to memorialize some of the discussions surrounding contentious VAR issues, and it provides a basis for the technical discussion that occurred during the informal process. For the aforementioned discussion, the informal development group recommends approval of the accompanying SAR and the posting of the pro forma standards in order to continue the progress on the VAR standards.

Entity Participants


Entity Participants

Appendix B: Entity Participants

The below entities represent a non-exhaustive list of entities that had personnel that participated in the VAR informal development effort in some manner, which may include one of the following: direct participation on the ad-hoc group, inclusion on the wider distribution (the “plus” list), attendance at workshops or other technical discussions, participation in a webinar or teleconference, or by providing feedback to the group through a variety of methods (e.g., email, phone calls, etc.). Additionally, though not listed here, announcements were distributed to wider NERC distribution lists to provide the opportunity for entities that were not actively participating to join the effort.

Table 2: Entity Participation in VAR Informal Development

AES DTE Energy ISO-NE Pepco Holdings TECO Energy

Alcoa Duke ITC Transmission PGE Tenaska

Ameren Dynegy KCP&L PGN Texas MPA Arizona Public Service

Edison Mission Generation Luminant PJM Tri-State G&T

ATC EDPR MEAG PNM TVA

Austin Energy Enervision MidAmerican Energy PPL WAPA

BGE Entegra power Midwest ISO PSC WE Energies Black Hills Corporation Entergy MN Power PSE WFEC Bonneville Power Admin.

Entergy Fossil & Hydro National Grid PSEG WICF

BP epelectric NCEMC Rayburn Electric Wisconsin Public Service

Calpine ERCOT NERC San Francisco PU Xcel Energy CenterPoint Energy Essential Power LLC NextEra SCANA Regional Entities: City of Tallahassee Exelon Corp NiSource SCE FRCC Colorado Springs Utilities ExxonMobil Northeast Utilities Seminole electric MRO

ComEd FERC Nova Scotia Power Siemens NPCC

ConEd FPL NPPD SMUD RFC

Constellation Garland Power & Light NYISO

Snohomish County PUD SERC

Constellation Energy Nuclear Group (CENG) Hydro Quebec

Occidental Energy Ventures Corp.

Southern Company Services SPP

CSU Iberdrola Renewables OGE

Southwest Generation TRE

Dominion IMPA PacifiCorp Southwest Power Pool WECC

Entity Participants


Table 3: Other Outreach

NERC Standards and Compliance Workshop

ISO/RTO Council

NAGF NERC News

NERC Standards Committee EPRI


VAR Standard Drafting Team (SDT) Anticipated Date Location Event

July 2013 - SC Authorizes SAR and pro forma Standards for Posting

July 2013

Conduct Nominations for VAR Project

July 2013 - Post SAR and pro forma Standards for 45-Day Initial

Comment Period



September 2013 TBD VAR Standard Drafting Team Face to Face Meeting to

Respond to Respond to Initial Comments and Revise as Necessary




Authorities


July 18, 2013

Standards Committee Communication and Planning Subcommittee (SCCPS) Recommendations to the Standards Committee (SC)

Action Approve the following SCCPS recommendations:

1. Add a standing item for “Communication Activities and Issues” to the agendas of the SC, the Project Management and Oversight Subcommittee (PMOS), and the Standards Committee Process Subcommittee (SCPS).

2. Incorporate a function related to stakeholder communication and outreach into the SC and SCPS charters.

3. Develop a roster with a pool of observers interested in providing communication feedback on an ad hoc basis on draft agendas for NERC standards workshops and webinars, changes to the Weekly Standards Bulletin, communication tools related to specific projects, and other products as needed.

4. Retire the SCCPS upon approval of these recommendations. Background In the past several months, as NERC staff, SCCPS members, and SC leadership worked to address leadership changes in the SCCPS, the SCCPS revisited an idea it had discussed before: reimagining the subcommittee in the changed SC landscape that includes the PMOS and a heightened awareness of the importance of communication. Retiring the SCCPS and formalizing the focus on communication through agenda and charter changes and the communication-focused roster of observers is the logical next step for two reasons: First, the SCCPS has, in some respects, completed its most important task. It has socialized the importance of communication among the SC, such that most SC members are paying attention to communication, as is NERC staff and now the PMOS, with its focus on informal outreach and consensus building related to projects. Further, NERC Standards Developers know that incorporating communication into their work is vital to success. Second, the SCCPS’s function has always been to facilitate communication; SCCPS members were not close enough to projects or issues to advocate for them, nor was that role appropriate. Thus, the communication activities encouraged by the SCCPS were typically left to NERC staff, drafting team members, or SC members. In a focused discussion during its June 4, 2013 meeting, SCCPS members determined the most important communication functions to retain are:

• The ability for stakeholders who identify communication issues to raise them to the SC or NERC staff, and

• The general ability for stakeholders to offer feedback on communication products. SCCPS members agreed that a formal subcommittee was no longer the best solution for these activities. SCCPS members believe the recommendations above ensure an ongoing, efficient


July 18, 2013

focus on communication, while maintaining a pool of stakeholders to provide communication feedback in a low-commitment way. With respect to the first recommendation, the SCCPS envisions that topics for the standing communication item on the SC agenda will be submitted by SC members and observers, NERC staff, and PMOS and SCPS members after their own communication discussions. For instance, PMOS liaisons may, in their engagement with drafting teams, identify issues that require broader SC support for addressing. Or the SCPS may develop a new document that requires a webinar and news article to inform the industry. NERC staff may also want SC feedback on the best strategy for communicating about a new initiative. With respect to the second recommendation, the SCCPS does not wish to be prescriptive about the incorporation of a communication function into the SC and SCPS charters, but it recognizes that some formalization of that function may be appropriate, whether in an immediate charter revision or in planned charter revisions at the end of the year. The SCCPS envisions that the third recommendation, the roster of observers, can initially be developed using prior SCCPS members. It can be maintained by NERC staff, in coordination with the SC, and updated, as needed, through regular solicitation of interested observers at Standards and Compliance Workshops and other appropriate forums. Once these recommendations are approved for implementation, the SCCPS can be retired, as suggested by the fourth recommendation. As a reference for SC members in considering this recommendation, SCCPS members have provided the attached table, which indicates how all functions from the current SCCPS charter, approved by the SC on March 7, 2013 as agenda item 3b, will be addressed going forward.

http://www.nerc.com/comm/SC/Agenda%20Highlights%20and%20Minutes/sc_20130307_agenda_package.pdf�


July 18, 2013

Function from SCCPS Charter How Function Will Be Addressed Going Forward A. Facilitate NERC and Standards Committee Stakeholder Outreach.

The Subcommittee will support NERC and the Standards Committee by developing and implementing communications plans and communicating with stakeholders to identify issues and share information about standards development activities and standards under development. The Subcommittee also coordinates with the NERC Regional Communications Group. The Subcommittee’s communication work will include but not be limited to the following:

Drafting teams are doing a good job developing and implementing communication plans for their projects. And that function is already formally one of their responsibilities. Among other references, the Roles and Responsibilities: Standard Drafting Teams Activities document, approved by the SC in July 2011, requires drafting teams to “engage stakeholders during standards development to help build industry consensus.” Drafting teams regularly hold webinars and conduct outreach on their projects. And NERC standards staff will continue to coordinate with the Regional Communications Group.

• Facilitating communication about regular NERC and Standards Committee work, such as core standards work areas and Standards Committee guiding documents

NERC staff handles communication about NERC work, and standing communication-related agenda items on the SC, PMOS, and SCPS agendas will ensure that additional feedback can be provided about NERC issues that need more focused communication. Communication about SC work will also be captured in the standing agenda item about communication, and communication tasks would be delegated to NERC staff, drafting teams, subcommittees, or an ad hoc communication group made up of SC members and/or observers, as deemed appropriate.

• Advising and assisting NERC staff and the Standards Committee with the Reliability Standards Development Plan communications plan

Communication about the RSDP will be captured in the standing agenda item about communication, and communication tasks would be delegated to NERC staff or an ad hoc communication group made up of SC members and/or observers, as deemed appropriate.

• Advising and assisting NERC staff and the Standards Committee with communications about the Standard Processes Manual

Communication about SPM changes will be captured in the standing agenda item about communication, and communication tasks would be delegated to NERC staff or an ad hoc communication group made up of SC members and/or observers, as deemed appropriate. Approval of the latest version of the SPM, for instance, will be announced in the Weekly Standards Bulletin and NERC staff, working with the SC, can hold a webinar when it’s approved to remind stakeholders of the changes that will be going into effect.

• Supporting outreach on NERC staff’s standards-related training initiatives, such as Standards Committee charter processes and procedures related to standards project

Communication about training initiatives will be captured in the standing agenda item about communication, and communication tasks would be delegated to NERC staff or an ad hoc communication group

http://www.nerc.com/pa/Stand/Resources/Documents/RolesandResponsibilitiesApprovedJuly13.pdf�


July 18, 2013

development made up of SC members and/or observers, as deemed appropriate. B. Support Standard Drafting Team Communication Efforts. The

Subcommittee will support standard drafting teams in communicating about their projects to encourage transparency and open communication to help stakeholders make informed decisions. This may include collaborating with standard drafting team leadership, reviewing communication plans and proposing changes, assisting in message development, and identifying issues that require clarification.

This responsibility is already delegated to the PMOS in the PMOS charter (approved by the SC on June 4, 2013 as agenda item 4b). From Section 2: Overview & Functions, item 1b requires the PMOS to “work with NERC staff to develop and refine project management tools such as dashboards, project charting for tracking projects and communicating the status of projects.” Item 3c from that section requires the PMOS to “work with the SC Chair, Vice Chair and NERC standards developer to ensure SAR drafting teams and SDTs use informal methods to actively gain consensus during both the informal development period as well as during the formal project development period. These informal methods may include but are not limited to outreach to individual industry experts and trade associations, webinars and workshops.”

C. Support NERC Staff in Planning and Identify Topics for Outreach Events. The Subcommittee recommends topics for standards workshops and webinars and works with NERC staff in the development of workshop and webinar agendas to ensure that adequate time is allocated to discussion of timely standards development issues and activities that are of greatest value to the industry. The Subcommittee may identify and take advantage of other forums for providing similar visibility and discussion of proposed standards and related issues. These include, but are not limited to, the following:

• Annual State of Standards Webinar • NERC Standards & Compliance 101 • Bi-annual NERC Standards and Compliance Workshops • Opportunities for NERC staff or Standards Committee

officers to present at regional and industry technical committee meetings, seminars, workshops, and conference calls

Feedback about outreach events will continue to be solicited at the outreach events themselves, and the roster of observers interested in providing ad hoc communication feedback will be asked to provide input on draft agendas.

D. Other Duties. The Subcommittee will work on other tasks as the Subcommittee identifies or as directed by the Standards Committee, including but not limited to:

Communication about these kinds of initiatives would be captured in the standing agenda items on communication, and communication tasks would be delegated to NERC staff or an ad hoc communication

http://www.nerc.com/comm/SC/Agenda%20Highlights%20and%20Minutes/sc_2013060513a_agenda_package_060413.pdf�


July 18, 2013

• Advising NERC staff on standards-related IT projects, webpage design, and electronic communications that will enhance communications of standards development issues and activities with the industry

• Refining NERC’s communication tools (e.g., the communication plan template, the Weekly Standards Bulletin, and standards announcements), as needed

group made up of SC members and/or observers, as deemed appropriate.

Agenda Item 10b Standards Committee

July 18, 2013

SCPS Report on Ongoing Tasks Action Information only.

Background Ben Li, co-chair of the SCPS, will provide an update on the subcommittee’s current activities. Guy Zito will provide an update on the Cost Effectiveness Analysis Process (CEAP) Phase II pilot project.

Agenda Item 10b-1 Standards Committee

July 18, 2013

Status of SCPS Assignments – As of July 3, 2013

Task Primary Contact (Team Lead)

Target Completion

Status

“Single Portal”

Phase I – to manage requests for clarification

Phase II – to manage requests for standard development and identification of reliability issues

Guy Zito

09/2013

12/2013

Ongoing

Ongoing

Improving Consensus Building at the SAR stage David Kiguel

09/2013 Being revised to address comments received at the June 2013 SC meeting

Incorporating Quality Review into Standard Drafting Keith Porterfield

09/2013 Finalizing process and QR template

Updating Drafting Team Guidelines Guy Zito 09/2013 Ongoing

Consolidate SC resource documents

- Propose a list of documents to be retired

- Consolidate remaining documents

Guy Zito

08/2013

12/2013

Ongoing

Ongoing

Expanding Violation Risk Factors to a Five Tier Structure Pete Heidrich

12/2013 Ongoing

Assignment Resulting 2013 Strategic Work Plan – Task #2: Improve standards development process

Joe Tarantino

12/2013 Ongoing. Major effort put on hold pending gaining some experience with the new SPM

Agenda Item 10b-1 Standards Committee

July 18, 2013

Status of SCPS Assignments – As of July 3, 2013

Task Primary Contact (Team Lead)

Target Completion

Status

Assignment Resulting 2013 Strategic Work Plan – Task #6: Revise SCPS charter and develop work plan

Linda Campbell

09/2013 Ongoing

CEAP Pilot Guy Zito 12/2013 Phase I completed; Phase II underway. Guy Zito to provide an update at the July SC meeting.

Revise interpretation process/procedure Steve Noess 09/2013 Ongoing

Agenda Item 10c Standards Committee

July 18, 2013

Project Management Oversight Subcommittee (PMOS) Update Action None requested. Update Only.

Background The PMOS continues to refine the Project Tracking Spreadsheet tool to take into account Standards Committee member and interested stakeholder comments. NERC staff intends to continue to update and post the Project Tracking Spreadsheet on a monthly basis. The PMOS held its scheduled conference call on June 17th and participated in a Lessons Learned webinar with the Cold Weather Preparedness Drafting Team. Each active project has been assigned a liaison and the liaisons continue their outreach to the NERC Standard Developers. In the coming months, the PMOS liaisons will continue to work with the Standard Developers and standard drafting teams to discuss and improve the PMOS processes including documentation of reasons for schedule slippage on the Project Tracking Spreadsheet. Going forward, Standard Developers will be required to include comments for all yellow, red and black projects on the Project Tracking Spreadsheet that indicate the reasons for delay as well as the steps that are being taken to address the identified issues. Additionally, the training material for the standard drafting teams will be updated to include information on the PMOS processes and expectations.

Agenda Item 10d

Standards Committee July 18, 2013

Functional Model Working Group

Action Approve one of the following approaches to completing task 6 of the 2013-2015 Standards Committee Strategic Work Plan, related to the Functional Model Working Group:

1. Reform the Functional Model Working Group to an Advisory Group to the Standards Committee after the completion of two outstanding projects: (1) working with the Planning Committee on Demand Response, as assigned to it in the January Standards Committee meeting, and (2) Project 2010-08 – consistency of definitions. (See recommendations of FMWG attached).

2. Reform the Functional Model Working Group to an Advisory Group to the Standards Committee after the completion of working with the Planning Committee on Demand Response, as assigned to it in the January Standards Committee meeting, and assign Project 2010-08 – consistency of definitions – to a new standard drafting team to be publically solicited.

3. Disband the Functional Model Working Group after the completion of two outstanding projects: (1) working with the Planning Committee on Demand Response, as assigned to it in the January Standards Committee meeting, and (2) Project 2010-08 – consistency of definitions.

4. Disband the Functional Model Working Group after the completion of working with the Planning Committee on Demand Response, as assigned to it in the January Standards Committee meeting, and assign Project 2010-08 – consistency of definitions – to a new standard drafting team to be publically solicited.

Background Task 6, Part 3 of the 2013-2015 Strategic Work Plan states: “….The FMWG shall develop recommendations for the SC on whether to continue the operation of the FMWG. These recommendations should be presented for SC consideration no later than the SC’s June face -to-face meeting.” Consistent with Task 6, the above options are provided to the Standards Committee for consideration along with the FMWG’s recommendations – attached.

Agenda Item 10d-2 Standards Committee Meeting

July 18, 2013

Reactivation of Project 2010-08 and Status of Functional Model Work Group Projects and Reforms

Actions Requested of the Standards Committee 1. Authorize Project 2010-08 to be reactivated and authorize the posting for SC review and approval, based on its SAR. Direct the FMWG to develop and present a project plan to the SC at its August 2013 meeting. The project plan shall set forth an approach to complete the recirculation ballot for Project 2010-08 by the end of September 2013. The project plan may include the use of informal consensus building tools to re-educate stakeholders on the purpose of the project and facilitate successful balloting. 2. Accept the FMWG’s recommendation that the FMWG be transitioned to an Advisory Group that reports to the Standards Committee once it has completed its two outstanding projects. Background Task 6 of the Standards Committee Strategic Work Plan 2013-2015 stated, in part, “The FMWG shall develop a recommendation for the SC on whether to continue the operation of the FMWG. This recommendation should be presented for SC consideration no later than the SC’s XXXX meeting.” FMWG provided an initial update at the March 2013 SC meeting, which included consideration of its two outstanding projects. The first project relates to a request made by the NERC Planning Committee to assess the need for introducing Demand Response functions and associated entities to the NERC Functional Model. This project is being coordinated with the Planning Committee and is expected to be completed by the end of September. The second project – Project 2010-08 Functional Model Glossary Revisions – is currently suspended. This project is designed to align the definitions of various functional entities between the Functional Model, the NERC Glossary of Terms, and the NERC Statement of Compliance Registration Criteria. The status of this project is that a SAR was issued, comments received, and a response to comments developed and posted. A summary document highlighting changes made to some functional entities’ definitions based on comments was prepared and posted. Regarding the continued operation of the FMWG, the consensus was that a panel of experts on the Functional Model is needed on an ongoing basis Thus, the group recommends that the Working Group be transitioned to an Advisory Group that reports to the Standards Committee. The group discussed several options. The rationale for switching to an Advisory Group is:

FMWG’s expertise has been sought from time to time when it comes to standards drafting. A group familiar with the Functional Model can be mobilized quickly when new issues (like

Demand Resources or Gas Supply Reliability) arise that requires an assessment of how they fit into the Functional Model.

The elimination of the FMWG completely could result in SDTs writing standards requirements which may lead to unintended, inadvertent creation of or revision to “Applicable Entities” without understanding the consequences of those changes.

Elimination of the FMWG will result in the loss of institutional knowledge gained over many years which is of invaluable benefit to the quality of standards and the efficiency of the standards development process

An Advisory Group would keep the core of Functional Model experts together with minimal NERC staff support.

July 2013 Item 11

NERC Legal and Regulatory Filings - Standards

RECENT FILINGS

DATE PROJECT/DESCRIPTION May 10, 2013 Definition of Adequate Level of Reliability, Docket No. RR06-1

May 10, 2013 Project 2012-08.1

Phase 1 of Glossary Updates: Statutory Definitions , Docket No. RD13-10

May 13, 2013 Comments in response to the MOD-28 NOPR, Docket No. RM12-19

May 23, 2013 Motion for an Extension of Time of the effective date of BES, Docket No. RM12-6 and RM12-7

May 30, 2013 Petition for approval of Project 2007-09 ― Generator Verification ― MOD-025-2, MOD-026-1, MOD-027-1, PRC-019-1 and PRC-024-1, Docket No. RM13-16

May 31, 2013 Quarterly filing regarding timeframe to restore power to the auxiliary power systems of U.S. Nuclear Power Plants following a blackout as determined during simulations and drills of system restoration plans, Docket No. RM06-16

June 3, 2013 Compliance filing in response to the Order on ERO Definition of BES and Rules of Procedure, Docket No. RM12-6 and RM12-7

June 4, 2013 Reply Comments of NERC in Response to Comments on Motion for an Extension of Time of the effective date of BES, Docket No. RM12-6 and RM12-7

June 10, 2013 Notice of Filing of Project 2007-09 ― Generator Verification ― MOD-025-2, MOD-026-1, MOD-027-1, PRC-019-1 and PRC-024-1, (Canadian Provinces - Alberta, British Columbia, Manitoba, New Brunswick, National Energy Board, Ontario, Quebec, Saskatchewan)

June 24, 2013 Comments in Response to Supplemental Notice of Proposed Rulemaking, TPL-001-4, Docket No. RM12-1, RM13-9

June 24, 2013 Comments in response to the GOTO NOPR, Docket No. RM12-16 June 24, 2013 Comments in response to the CIP NOPR, Docket No. RM13-5 July 8, 2013 Comments in response to the proposed remand of BAL-002, RM13-6

UPCOMING FILING DATES

DATE PROJECT/DESCRIPTION July 9, 2013 Reply comments in response to the GOTO NOPR, Docket No. RM12-

16 July 12, 2013 Compliance filing on FAC-003-2 Order July 31, 2013 Quarterly Report of the North American Electric Reliability Corporation

on the Analysis of Standard Process Results for the Second Quarter 2013, Docket Nos. RR06-1 and RR09-7

http://www.nerc.com/filez/alrtf.html�

http://www.nerc.com/filez/standards/Project_2012-08.1_Phase_1_Glossary_Updates_Statutory_Definitions.html�

http://www.nerc.com/filez/standards/Generator-Verification-Project-2007-09.html�

http://www.nerc.com/filez/standards/Generator-Verification-Project-2007-09.html�

July 2013

2

DATE PROJECT/DESCRIPTION August 27, 2013 Comments in response to the P81 NOPR, Docket No. RM13-8 August 29, 2013 Quarterly filing to Nova Scotia of FERC-approved Reliability Standards

PROJECTED FILINGS

STATUS PROJECT/DESCRIPTION Status: BOT Approved Projected Filing Date: TBD

COM Standards: (2006-06 - Reliability Coordination – COM-001-2 and COM-002-3 / Project 2009-22 - Interpretation of COM-002-2)

Status: BOT Approved Projected Filing Date: July 2013

Regional Reliability Standard IRO-006-WECC-2

Status: BOT Approved Projected Filing Date: July 16, 2013

Regional Reliability Standard BAL-004-WECC-2 and BAL-001-1

Standards Committee Expectations Approved by Standards Committee January 12, 2012 Background Standards Committee (SC) members are elected by members of their segment of the Registered Ballot Body, to help the SC fulfill its purpose. According to the Standards Committee Charter, the SC’s purpose is:

In compliance with the NERC Reliability Standards Development Procedure, the Standards Committee manages the NERC standards development process for the North American-wide reliability standards with the support of the NERC staff to achieve broad bulk power system reliability goals for the industry. The Standards Committee protects the integrity and credibility of the standards development process.

The purpose of this document is to outline the key considerations that each member of the SC must make in fulfilling his or her duties. Each member is accountable to the members of the Segment that elected them, other members of the SC, and the NERC Board of Trustees for carrying out their responsibilities in accordance with this document. Expectations of Standards Committee Members 1. SC Members represent their segment, not their organization or personal views. Each member is

expected to identify and use mechanisms for being in contact with members of the segment in order to maintain a current perspective of the views, concerns, and input from that segment. NERC can provide mechanisms to support communications if an SC member requests such assistance.

2. SC Members base their decisions on what is best for reliability and must consider not only what is best for their segment, but also what is in the best interest of the broader industry and reliability.

3. SC Members should make every effort to attend scheduled meetings, and when not available are

required to identify and brief a proxy from the same segment. Standards Committee business cannot be conducted in the absence of a quorum, and it is essential that each Standards Committee make a commitment to being present.

4. SC Members should not leverage or attempt to leverage their position on the SC to influence the outcome of standards projects.

5. The role of the Standards Committee is to manage the standards process and the quality of the output, not the technical content of standards.

http://www.nerc.com/files/Standards_Committee_Charter_Final.pdf�

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Item 12a

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Standards Committee 2013 Segment Representatives

*New to Standards Committee

Segment and Term Representative Organization

Chairman

2013

Brian Murphy

Manager, NERC Reliability Standards Compliance

NextEra Energy, Inc.

Vice-chairman

2013

Scott Miller

Manager, Corporate Affairs

MEAG Power

Segment 1-2013-14 Lou Oberski

Managing Director, NERC Compliance Policy

Dominion Resources Services, Inc.

Segment 1-2012-13 Carol A. Sedewitz

Director, Transmission Planning

National Grid

Segment 2-2013-14 Charles Yeung*

Executive Director Interregional Affairs

Southwest Power Pool

Segment 2-2013 Ben Li

Consultant

Independent Electric System Operator

Segment 3-2013-14 Jennifer Sterling

Director, Exelon NERC Compliance Program

Exelon

Segment 3-2012-13 John Bussman

Manager Reliability Compliance

Associated Electric Cooperative Inc.

Segment 4-2013-14 Joseph Tarantino

Regulatory Compliance Coordinator

Sacramento Municipal Utility District

Segment 4-2012-13 Frank Gaffney

Assistant General Manager of and Officer of Regulatory Compliance

Florida Municipal Power Authority

Segment 5-2013-14 Gary Kruempel

Compliance Director, Energy Supply

MidAmerican Energy Company

Agenda Item 12b Standards Committee

July 18, 2013

Standards Committee 2013 Roster 2

Segment and Term Representative Organization

Segment 5-2013 Randy Crissman*

Vice President – Technical Compliance

New York Power Authority

Segment 6-2013-14 Brenda Hampton*

Regulatory Policy

Energy Future Holdings – Luminant Energy Company LLC

Segment 6-2013 Andrew Gallo*

Director, Reliability Compliance

City of Austin dba Austin Energy

Segment 7-2013-14 John A. Anderson

President & CEO

Electricity Consumers Resource Council

Segment 7-2012-13 Frank McElvain

Senior Consulting Manager

Siemens Energy, Inc.

Segment 8-2013-14 Robert Blohm*

Managing Director

Keen Resources Asia Ltd.

Segment 8-2012-13 Frederick Plett

Utility Analyst

Massachusetts Attorney General

Segment 9-2013-14 Diane J. Barney

Utility Supervisor

New York State Public Service Commission

Segment 9-2012-13 Klaus Lambeck

Chief Facilities, Siting and Environmental Analysis

Public Utilities Commission of Ohio/the Ohio Power Siting Board

Segment 10-2013-14 Steve Rueckert

Director of Standards

Western Electricity Coordinating COuncil

Segment 10-2012-13 Linda Campbell

Vice President and Executive Director, Standards and Compliance

Florida Reliability Coordinating Council

Canada 2013 David Kiguel

Manager, Reliability Standards

Hydro One Networks Inc.

Parliamentary Procedures Based on Robert’s Rules of Order, Newly Revised, 10th Edition, plus “Organization and Procedures Manual for the NERC Standing Committees”

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

When you want to… Procedure Debatable Comments

Raise an issue for discussion

Move Yes The main action that begins a debate.

Revise a Motion currently under discussion

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

Reconsider a Motion already approved

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

End debate Call for the Question or End Debate

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

Record each member’s vote on a Motion

Request a Roll Call Vote

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

Postpone discussion until later in the meeting

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

Postpone discussion until a future date

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

Remove the motion for any further consideration

Postpone indefinitely

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

Request a review of procedure

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

Notes on Motions

Seconds. A Motion must have a second to ensure that at least two members wish to discuss the issue. The “seconder” is not recorded in the minutes. Neither are motions that do not receive a second.

Announcement by the Chair. The Chair should announce the Motion before debate begins. This ensures that the wording is understood by the membership. Once the Motion is announced and seconded, the Committee “owns” the motion, and must deal with it according to parliamentary procedure.

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Voting Voting Method When Used How Recorded in Minutes

Unanimous Consent When the Chair senses that the Committee is substantially in agreement, and the Motion needed little or no debate. No actual vote is taken.

The minutes show “by unanimous consent.”

Vote by Voice The standard practice. The minutes show Approved or Not Approved (or Failed).

Vote by Show of Hands (tally) To record the number of votes on each side when an issue has engendered substantial debate or appears to be divisive. Also used when a Voice Vote is inconclusive. (The Chair should ask for a Vote by Show of Hands when requested by a member).

The minutes show both vote totals, and then Approved or Not Approved (or Failed).

Vote by Roll Call To record each member’s vote. Each member is called upon by the Secretary,, and the member indicates either “Yes,” “No,” or “Present” if abstaining.

The minutes will include the list of members, how each voted or abstained, and the vote totals. Those members for which a “Yes,” “No,” or “Present” is not shown are considered absent for the vote.

Notes on Voting (Recommendations from DMB, not necessarily Mr. Robert)

Abstentions. When a member abstains, he is not voting on the Motion, and his abstention is not counted in determining the results of the vote. The Chair should not ask for a tally of those who abstained.

Determining the results. The results of the vote (other than Unanimous Consent) are determined by dividing the votes in favor by the total votes cast. Abstentions are not counted in the vote and shall not be assumed to be on either side.

“Unanimous Approval.” Can only be determined by a Roll Call vote because the other methods do not determine whether every member attending the meeting was actually present when the vote was taken, or whether there were abstentions.

Majorities. Robert’s Rules use a simple majority (one more than half) as the default for most motions. NERC uses 2/3 majority for all motions.

Standards Committee Meeting Dates and Locations for 2013 Update

Conference calls are held each month where the SC does not have a face-to-face meeting. These calls are on one Thursday each month from 1-5 pm Eastern. Face-to-face meetings are conducted from 8-5 pm on the first day and 8-3 pm the second day. The time for face-to-face meetings is based on the ‘local’ time zone. The time specified for all conference calls is based on the Eastern time zone. In order to schedule the face-to-face meetings so they align with the standing committee meetings and occur two months prior to each NERC Board of Trustees meeting, the January face-to-face will occur as scheduled with the next face-to-face in March. This realignment will also call for a fifth face-to-face meeting in December. Further, because there is a face-to-face meeting in the middle of January and another in the beginning of March, there will not be a conference call held in February.

• January 16-17, 2013 – Atlanta (8-5 p.m. January 16; 8-3 p.m. January 17) • February 2013 – no conference call • March 7-8, 2013 – Albuquerque (8-5 p.m. March 7; 8-3 p.m. March 8) • April 4, 2013 conference call from 1-5 p.m. • May 2, 2013 conference call from 1-5 p.m. • June 5-6, 2013 – Atlanta (8-5 p.m. June 5; 8-3 p.m. June 6) • July 18, 2013 conference call from 1-5 p.m. • August 22, 2013 conference call from 1-5 p.m. • September 19, 2013 – Denver (8-5 p.m.) • October 17, 2013 conference call from 1-5 p.m. • November 14, 2013 conference call from 1-5 p.m. • December 11-12, 2013 – Atlanta (1-5 p.m. December 11; 8-noon December 12)

The Standards Committee has two subcommittees (Communications and Planning Subcommittee and Process Subcommittee) and these typically meet for either a whole day or a half day on the day immediately preceding the Standards Committee’s face-to-face meetings. Thus, expect a meeting of the subcommittees on the following dates:

• January 15, 2013 in Atlanta • March 6, 2013 in Albuquerque • June 4, 2013 in Atlanta

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Item 12d

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Standards Committee Meeting Dates and Locations for 2013 2

• September 18, 2013 in Denver • December 11, 2013 in Atlanta