Agenda
Operating Committee
June 6, 2007  1 p.m. to 5 p.m.
June 7, 2007  8 a.m. to noon
Toronto Marriott Downtown Eaton Centre
525 Bay Street, Toronto, Ontario, Canada
416-597-9200
Item
Leader
1. Administration
Secretary
Action
a. Quorum
b. Procedures
c. Introductions
d. Agenda
Chairman
Approve
2. Consent Agenda
Chairman
Approve
3. FYI  E-tag 1.8
Pat Doran
Discuss
4. Committee Officer Elections
Secretary
Approve
5. NERC Compliance Filing on Reliability Enhancement
Programs
Dave Nevius
Discuss
Approve
6. Reliability Criteria and System Limit Concepts
7. Defining “Adequate Level of Reliability”
Chairman
Discuss
8. Standards BAL-007 through -011
Raymond Vice
Discuss
9. Time Error Monitoring and Correction
Terry Bilke
a. Time Error Monitor
Discuss
b. Time Error and Inadvertent Management Procedures
Discuss
10. Real-time Operations SAR
Secretary
Discuss
11. Demand Response
Dave Nevius
Discuss
12. Reliability Coordination
Designate and Permit
a. Reliability Coordination Information System
b. Reliability Plan  SaskPower
Walter Omoth
Approve
Ross Wilkinson
c. Reliability Plan  WECC
13. Reliability Readiness Program
Approve
Richard Schneider
Discuss
14. Next Meeting
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
Operating Committee Meeting
June 67, 2007
Item 1.
Administration
Item 1.a
Announcement of Quorum
The secretary will announce whether a quorum (two-thirds of the
voting members) is in place. NOTE: The committee cannot conduct
business without a quorum. Please be prepared to stay for the entire
meeting.
Item 1.b
Procedures
The NERC Antitrust Compliance Guidelines, Operating Committee
charter, and a summary of Parliamentary Procedures are attached for
reference. The secretary will answer questions regarding these
procedures.
Attachments
 Antitrust Guidelines

Operating Committee Charter

Parliamentary Procedures
Item 1.c
Introduction of Members and Guests
The chairman will ask the committee members and guests to introduce
themselves.
Attachment
Operating Committee roster
Item 1.d
Approval of Agenda
Action
Approve meeting agenda.
Background
The chairman will review the agenda, ask for amendments, and then
approval.
Operating Committee Meeting
June 67, 2007
Item 2.
Consent Agenda
The consent agenda allows the Operating Committee to approve
routine items that would not normally need discussion. Any OC
member may ask the chairman to remove an item from the consent
agenda for formal discussion and action.
Action
Approve the attached document.
Attachment
 Minutes of March 2122, 2007 Operating Committee meeting.
Operating Committee Meeting
June 67, 2007
Item 3.
FYI – E-tag 1.8
The Interchange Subcommittee has been working on the E-tag
revisions. Subcommittee member Pat Doran from the IESO will be
available to answer questions about this project.
Operating Committee Meeting
June 67, 2007
Item 4.
Committee Officer Elections
Action
Elect committee officers for July 1, 2007June 30, 2009.
The Nominating Subcommittee recommends Gayle Mayo as chair and
Sam Holeman as vice chair.
Background and Procedure
Section 4 of the Operating Committee charter explains the terms,
conditions, and procedures for selecting the committee’s officers. The
Operating Committee uses a nominating subcommittee to provide a
slate of candidates for the committee’s consideration. (Secretary’s
note: Members of the nominating subcommittee are eligible for
nomination.)
1. The nominating subcommittee will present its candidate for chair.
2. The committee chairman will then open the floor for additional
nominations, and
3. The committee will then vote on the candidates in the order they
were nominated.
4. The first candidate to garner a majority (the charter states
“majority” in this instance) of the votes is elected
a. If there is only one nominee, that person is automatically
elected.
We will repeat this process for the vice chair candidate.
Nominating
Subcommittee
Derek Cowbourne (chair)
Bill Hatfield
Sam Holeman
Van Wardlaw
John Powell
Operating Committee Meeting
June 67, 2007
Item 5.
NERC Compliance Filing on Reliability Enhancement
Programs
Discussion Item
Dave Nevius will lead the discussion of NERC’s draft filing on
reliability enhancement programs.
Attachment
“Compliance Filing on Reliability Enhancement Programs,” in
response to paragraph 468 of Order No. 672
Background
The Commission requires the electric reliability organization (pursuant
to Section 215 of the Federal Power Act) to make a compliance filing
no later than one year from the date of certification “proposing
reliability enhancement programs that would improve Bulk-Power
System reliability, along with a program implementation schedule.”
In this filing (attached), NERC describes a number of programs and
initiatives it has implemented or is in the process of implementing that
have the objective of improving the reliability of the bulk power
system.
We invite the Operating Committee to review this filing and provide
comments to Dave Nevius.
Operating Committee Meeting
June 67, 2007
Item 6.
Reliability Criteria and System Limit Concepts
Action
Approve posting the Reliability Concepts document for industry
comment. This is a follow-up to the morning’s joint meeting.
Attachments

Letter from Al Miller to the Planning Committee and Operating
Committee, May 2, 2007

We will post the lastest “Reliability Criteria and Operating Limit
Concepts” document in the joint OC/PC meeting agenda next
week.
Background
We will start with an overview at the joint OC/PC meeting, and then
provide time for each committee to discuss the reliability concepts at
their own meetings.
These are very important discussions because the concepts and ideas
before us will, we hope, guide drafting teams as they prepare revisions
to our reliability standards in the future. These concepts are also key to
the Federal Energy Regulatory Commission’s judgment of our
standards as providing an “adequate level of reliability,” a term the
Commission has asked NERC to define (see following agenda item).
The letter from Al Miller (attached) provides the background for the
concepts document.
Operating Committee Meeting
June 67, 2007
Item 7.
Defining “Adequate Level of Reliability”
Discussion Item
This is a follow-up to the joint OC/PC meeting on this topic.
Background
In its January 18, 2007 order on compliance filing, FERC directed
NERC to file a plan for defining “adequate level of reliability.” The
Commission will use that definition when judging the merits of
NERC’s reliability standards against the requirements of Section 215
(c) of the Federal Power Act.
At this meeting, the Planning Committee and Operating Committee
will discuss a draft of this definition offered by the committee officers,
and review the plan for presenting the definition to the NERC Board of
Trustees in February 2008 and then filing this definition with the
Commission.
The Operating Committee and Planning Committee officers drafted
the following definition of “adequate level of reliability” for the
committees to discuss at this meeting. (The NERC staff was not
involved in their deliberations.)
“An adequate level of bulk power system reliability is required to
support the economy, the environment and public health and
safety. Adequate reliability is a targeted level of performance, as
simulated or in real-time, whereby the bulk power system has been
planned with enough reserve, or operated in such manner, so as to
supply the anticipated aggregate demand for electricity, including
reasonable forecasting error, while operating within equipment and
electric system thermal, voltage, and stability limits such that
instability, uncontrolled separation, or cascading failures of the
bulk power system will not occur as a result of the planned, or
unplanned, loss of bulk power system facilities as described in the
NERC Transmission Planning (TPL) standards. Adequate
reliability also includes the capability to respond to circumstances
outside the TPL standards and restore the bulk power system to
normal operation to effectively mitigate the impact on public
health and safety.”
Discussion Points
As the committees discuss this definition, we need to keep the
following points in mind:
1. Definition of adequate level of reliability in the context of
Section 215 (c) of the Federal Power Act:
(c) CERTIFICATION—Following the issuance of a Commission rule
under subsection (b)(2), any person may submit an application to the
Commission for certification as the Electric Reliability Organization.
Operating Committee Meeting
June 67, 2007
The Commission may certify 1 such ERO if the Commission determines
that such ERO—
(1) has the ability to develop and enforce, subject to subsection
(e)(2), reliability standards that provide for an adequate level of
reliability of the bulk-power system; and…. (Emphasis added)
The Commission is asking NERC to provide this definition so it can
judge our standards according to this provision in the act.
2. State savings provisions of the Act:
(i) SAVINGS PROVISIONS.—(1) The ERO shall have authority
to develop and enforce compliance with reliability standards for
only the bulk-power system.
(2) This section does not authorize the ERO or the
Commission to order the construction of additional
generation or transmission capacity or to set and
enforce compliance with standards for adequacy or
safety of electric facilities or services.
(3) Nothing in this section shall be construed to preempt
any authority of any State to take action to ensure the
safety, adequacy, and reliability of electric service within
that State, as long as such action is not inconsistent with
any reliability standard,…. (Emphasis added)
The savings provisions mean that NERC cannot compel any entity to
construct facilities. In other words, we cannot write standards that
require specific levels of generation reserves or ensure that all
customer demand is served.
3. Applicability of the definition.
The definition must be applicable to all NERC reliability standards.
When we submit a standard to the board and Commission for
approval, we will need to make sure that standard supports the
definition of adequate level of reliability. This includes standards on
planning, operations planning, and real-time operations. The Standards
Committee will revise the standards process by adding a reference to
this definition.
Procedure
NERC, through the PC and OC, committed to 1) develop a “straw
man” definition, 2) seek industry-wide comment, 3) request
Commission staff’s direct participation in these technical discussions,
and 4) otherwise coordinate with Commission staff at periodic
intervals throughout this process to obtain input and gauge
conformance to Commission expectations. Key PC/OC milestones:

December 31, 2007: After industry review and comment, propose
a definition to the NERC Board of Trustees.
Operating Committee Meeting
June 67, 2007

February 2008 Board of Trustees meeting: Present a
recommendation for board approval. The definition, as approved,
will be subsequently filed with the Commission and applicable
regulatory authorities in Canada.
Operating Committee Meeting
June 67, 2007
Item 8.
Standards – BAL-007 through -011
Discussion Item
Raymond Vice, a member of the Balance Resources and Demand
Standard Drafting Team, will solicit the Operating Committee’s
thoughts and suggestions on how to proceed with these standards.
Attachments

Ballot Results  BAL-007 through -011

Revised SAR, “Reliability-Based Control”

Letter – Gerry Adamski to Regional Managers – Extending the
Field Test, May 17, 2007
Summary
The ballot body did not approve these standards, and the Board of
Trustees would like the Operating Committee to provide its insight on
the outcome of the ballot and possible next steps for this standard.
The drafting team has fully explained the concept of these standards to
the Operating Committee over the past three years, focusing on the
Balancing Area ACE Limit (BAAL) concepts, and then on the results
of the field test. Mr. Vice, who is a member of the standard drafting
team, will review the ballot results and discuss the new SAR, which
the Standards Committee has already approved. The Standards
Committee is also forming a new standard drafting team.
Background
Proposed standards BAL-007 through -011 were not approved (the
ballot results are attached). At its May 2 meeting, the NERC Board of
Trustees discussed the results of the
ballot, and some board members asked
for additional insight into the reasons the
standard was not approved. What were
the reliability arguments? Would the
standard have been approved if more
utilities had participated in the field
trial? (See list at right.)
The standard drafting team regularly
visited the Operating Committee over
the past few years as the team developed
and tested the standard. The field trial
showed that interconnection frequency
had not deteriorated, though it did
exhibit frequency excursions around the time of the on-to-off peak
periods that were attributed to the end of the 16-hour on-peak energy
sales.
Items 8  10 deal
with NERC
standards.
Operating Committee Meeting
June 67, 2007
Just before the first ballot of the standard last fall, the Operating
Committee provided its opinion on the merits of the standard (see
following page). While the committee generally supported and
recommended the standard be approved, it also pointed out two
concerns: 1) The retirement of the Disturbance Control Standard at the
same time the new standards became effective, and 2) the effects of
the new Balancing Area ACE Limits on transmission line flow.
(Several OC members suggested keeping the DCS for 18 months, or
until the new BAAL standard proved to successfully deal with ACE
recovery after large generation failures.)
The standard was not approved, and several ballot body members cited
the retirement of the DCS as the reason for their negative vote. Others
noted their concern about the effects of the BAAL standard on line
flows.
The drafting team revised the implementation of the BAAL standard to
keep the DCS in place, and submitted the standard for a second ballot
this spring.
Analysis of Ballot Results
We can draw at least two conclusions from the ballot results:
1. Most of the negative ballots were from ballot body members in
WECC, NPCC, and FRCC. Most of them expressed their concern
about the potential for transmission line overloads caused by the
wider BAAL limits when the balancing authority was helping
interconnection frequency, and
2. The 14 field test participants represented about one-half of the
NERC-wide load, but only a small percentage of the 214 ballot
body members.
Therefore, even though the field test results have not linked
transmission line overloads to the BAAL standard, sufficient ballot
body members remained skeptical that this link would not materialize.
What’s Next
The Balance Resources and Demand standard drafting team has
proposed a new SAR (also attached) that adds transmission line
reliability to the BAAL standards. The drafting team is also actively
soliciting other utilities to participate in the field trial so they can see
first-hand whether the BAAL standards adversely affect transmission
system loading. The Standards Committee is forming a new drafting
team.
Operating Committee Meeting
June 67, 2007
Topics to Discuss
In addition to the proposed SAR, the Operating Committee should
consider these questions:
1. Does the revised SAR address the reliability issues that the
Operating Committee discussed last fall?
2. What role does field testing play when balloting a standard?
3. Does the OC have specific comments it would like to send the
drafting team?
Excerpt from September 1314, 2006 OC Meeting
Minutes: Opinion on BAL-007 through -011  Balance
Resources and Demand
Discussion
Standard drafting team member Doug Hils presented the latest results
of the field trial in which many utilities in the Eastern Interconnection
have been participating. This evoked considerable discussion within
the committee. Most of the comments focused on the planned
retirement of standard BAL-002, also known as the Disturbance
Control Standard (DCS), within 18 months of the implementation of
new Balancing Area ACE Limits (BAAL) standards. Retiring the DCS
effectively extends the recovery time for generation loss to 30 minutes
because the BAAL standards do not distinguish generation loss from
other events that result in a large area control error.
Some committee members were concerned that allowing balancing
authorities more leeway in controlling their ACE when the
Interconnection frequency error was low could result in more
unscheduled interchange, and increased line loading. Mr. Hils noted
that, so far, the field trial has not turned up this problem.
Opinion
“The Operating Committee believes BAL-007 through -011 should be
approved. Eastern Interconnection frequency performance has been
consistent with previous years or improved since the field trials began.
The standard considers Interconnection frequency error and requires
balancing authorities to take action as the frequency approaches
specified high or low limits.
“The committee believes the Disturbance Control Standard should
remain in effect and be eliminated only after satisfactory field trials.”
Approved by show of hands: 23 in favor and 4 opposed.
Operating Committee Meeting
June 67, 2007
Item 9.
Time Error Monitoring and Correction
Item 9.a
Time Error Monitor
Discussion Item
The OC needs to discuss its expectations of the interconnection time
error monitors, considering they perform this task voluntarily.
Resources Subcommittee Chairman Terry Bilke will lead this
discussion.
Attachments

Memo – Roger Harszy to Dave Whiteley

Letter  Dave Whiteley to Roger Harszy, “Standard BAL-004,
‘Time Error Correction,’” May 11, 2007

NAESB Time Error Correction Business Practice
Background
Mr. Harszy’s memo requests a waiver for the Midwest Independent
System Operator (MISO) from BAL-004, requirement 2, considering
that MISO performs the time monitoring tasks voluntarily:
As Mr. Whiteley explained in his response, NERC cannot waive
compliance with its standards. We also explained that NERC would
not assess a penalty for non-compliance with requirement 2, and asked
MISO to continue serving voluntarily as the interconnection’s time
monitor until the Operating Committee resolved the issue.
Operating Committee Meeting
June 67, 2007
Ideas for Resolving Issue
Should we remove requirement 2 from BAL-004? (We would initiate
this with a SAR.) requirement 1 requires the time monitor to be a
reliability coordinator designated by the Operating Committee. Do we
need any other guidelines? For example, the Operating Committee
could establish this procedure:
Time Error Monitors and Correction
Approved by the Operating Committee: dd/mm/yyyy
Designated time monitors:
1.
2.
3.
4.
Correction procedures
1. Monitor time error.
2. Initiate or terminate time correction actions according to NAESB Time
Error Correction Business Practice or at the request of a reliability
coordinator or balancing authority.
We could place this in the Operating Manual.
Operating Committee Meeting
June 67, 2007
Item 9.b
Time Error and Inadvertent Management Procedures
Discussion Item
Terry Bilke will seek the Operating Committee’s opinions on a Time
and Inadvertent Management Procedure SAR for the Eastern
Interconnection.
Attachments

Standards Authorization Request, “Time and Inadvertent
Management Procedures (Eastern Interconnection)”

NAESB Inadvertent Interchange Payback Business Practice
Background
Here are the features of the SAR (excepted):
Change in Time Error Procedures: Expand the time window and reduce the
frequency offset such that TECs are implemented if Time Error exceeds ±20
seconds (East) at 22:00 Central Prevailing Time. If this threshold is reached,
a TEC is implemented at midnight (2 hours later) with a scheduled frequency
offset of +0.01Hz (rather than the present +0.02Hz)and run for a full clock day
(unless stopped for reliability reasons.
Unilateral Payback Correcting Time Error: In addition to current procedures,
allow unilateral payback via one of the following two methods whenever the BA
Inadvertent Interchange Balance and Time Error have the same sign:
ACE  ( I A  I S )  B( f A  f S )


An offset of scheduled frequency of +0.02 Hz, or
If the scheduled frequency setting cannot be offset, a Net Interchange
Schedule (MW) equal to 20% of the BA Bias.
This unilateral Inadvertent payback ends when the time error is zero or has
changed signs, the accumulation of inadvertent interchange has been corrected
to zero, or a scheduled time error correction begins, which takes precedence
over offsetting frequency schedule to pay back inadvertent.
Financial Settlement: Allowing financial settlement of Inadvertent Interchange
prevents a second flow of energy to correct an unscheduled flow of energy in
previous hours. The terms of the financial inadvertent settlement remain
private, the parties and amount of Inadvertent Interchange would be reported to
NERC. NAESB, at its discretion, may enact standards on terms and mechanisms for
settlement.
To provide assurance to the industry, the SAR proposes a field-trial of at
least 6 months to be followed by a performance report prior to a standard
being presented for ballot.
This standard would also require changes in the NAESB Time Error
and Inadvertent Interchange Payback Business Practices. The Eastern
Interconnection time error limits are now ± 10 seconds, and unilateral
payback limit is L10.
Operating Committee Meeting
June 67, 2007
Item 10. Real-time Operations SAR
Discussion Item
Don Benjamin will introduce this item.
This SAR has been posted for a 30-day comment period that ends on
June 13. So this would be an ideal time for the Operating Committee
to discuss the SAR and provide comments to the drafting team.
Attachment
Standards Authorization Request, “Real-time Operations”
Background
The SAR proposes changes to number of standards, including all the
TOP standards. The changes are generally aimed at reducing
redundant requirements (where the same language shows up in two
different standards) and tidying up the language. (Of course, “tidy” to
some is a major revision to others.)
SAR drafting team included several questions in the SAR comment
form, and the Operating Committee may wish to discuss the first two:
The first question asks, in essence, whether we need “best practices,”
or “guides.” The OC has discussed this in the past, and believes there
is merit in listing “good things to do.” The risk is they become de-facto
standards even though we would add warning labels that they are not.
If the OC still supports the idea of listing a set of guides, this is
something the OC subcommittees should pursue.
The second question asks whether NERC needs standards for
mitigating SOLs. SOLs are “local,” so to speak, and generally deal
with equipment protection, though mostly by inference (as in “you
Operating Committee Meeting
June 67, 2007
must operate within limits” as opposed to “you must not allow
equipment to exceed its short-term rating”).

Do we need standards for protecting equipment?

Do we need standards that require transmission operators to take
action, including load shedding, to protect equipment, or is that
intuitively obvious?

Given that SOLs can turn into IROLs, do we need SOL standards?
The Reliability Concepts document suggests new definitions of SOL
and IROL.
Operating Committee Meeting
June 67, 2007
Item 11. Demand Response
Discussion Item
Dave Nevius will lead this discussion.
This is a follow-up to the presentations on demand response at the
joint OC/PC meeting.
Operating Committee Meeting
June 67, 2007
Item 12. Reliability Coordination
Item 12.a Reliability Coordination Information System
Action
1. Designate the Reliability Coordinator Working Group (RCWG) as
the grantor of access to the Reliability Coordinator Information
System (RCIS), and, as part of this action,
2. Permit access (either read-only or read/write) to the RCIS only
upon the approval of the RCWG and as specified in the reliability
coordinators’ plans.
Background
NERC has maintained the Reliability Coordinator Information System
for many years as a Web-based communications system specifically
for the reliability coordinators. The NERC staff has been managing the
RCIS with help from the RCWG, and allows reliability coordinators to
participate in this system once the reliability coordinator’s plan is
approved.
Balancing Authority Access to RCIS
When the RCIS was first implemented, the balancing authorities and
transmission operators in the VACAR area were also provided access
because it provided them a simple way to communicate with their
reliability coordinator. This BA/TOP access is specified in VACAR’s
reliability coordinator plan, which the Operating Reliability
Subcommittee (ORS) and OC have approved.
Recently, the RCWG has received requests from other balancing
authorities, transmission operators, and regional council staff for either
read-only, or full read/write access to the RCIS. The working group
has discussed this issue but has not resolved it, deciding instead to
seek the Operating Committee’s counsel. One of the underlying
questions is “Who decides access rules for the RCIS?”
Recommendations from the Operating Reliability
Subcommittee
The Operating Reliability Subcommittee chairman, Jim Castle, and
NERC staff have discussed this, and we believe the Operating
Committee should consider two actions that would help the RCWG
address the RCIS access issue: First, recognizing that the Reliability
Coordinator Information System is primarily intended for reliability
coordinator communications, the Operating Committee should
designate the RCWG as the grantor of RCIS access. This would allow
the RCWG to allow access (either read-only or read/write as the
working group sees fit) to balancing authorities and transmission
Operating Committee Meeting
June 67, 2007
operators once those organizations have signed the necessary
confidentiality agreement, been listed in their respective reliability
coordinator’s plan, and the plan approved by the ORS. It would be up
to the RCWG to grant access to all other parties.
Second, the OC should agree that RCIS access is permitted only to
those organizations that are identified in the reliability coordinator’s
plan.
Item 12.b Reliability Plan – SaskPower
Action
Approve the SaskPower’s reliability
coordination plan.
Walter Omoth and Ross Wilkinson from
SaskPower will be available to answer
questions about this plan.
Attachment
“Reliability Coordinator Reliability Plan
for the SaskPower Subregion of the
Midwest Reliability Organization,”
March 20, 2007
Background
The Operating Reliability Subcommittee
has approved the SaskPower reliability
plan, subject to SaskPower successfully
completing a reliability coordinator
reliability readiness pre-operational
evaluation scheduled for this fall.
The ORS recommends the OC approve
the plan (attached), with the
understanding that 1.) the ORS will
grant access to the RC “tools” once the
subcommittee is satisfied with the
results of the pre-operational evaluation,
and 2.) the ORS will notify the OC of
the results of the evaluation.
The flowchart on the right shows where
we are in approving this plan.
Operating Committee Meeting
June 67, 2007
Item 12.c Reliability Plan – WECC
Action
Approve WECC’s reliability plan.
Attachment
“Western Electricity Coordinating Council Reliability Coordinator
Plan,” April 24, 2003
Background
The ORS recommends the OC approve the WECC plan (attached). No
pre-operational evaluation is necessary.
Operating Committee Meeting
June 67, 2007
Item 13. Reliability Readiness Program
Discussion Item
Richard Schneider will review the activities of the Reliability
Readiness Program.
Operating Committee Meeting
June 67, 2007
Item 14. Next Meeting