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					      NORTH AMERICAN ELECTRIC RELIABILITY COUNCIL
         Princeton Forrestal Village, 116-390 Village Boulevard, Princeton, New Jersey 08540-5731


                         Interchange Subcommittee Meeting
                        Wednesday, May 18, 2005 — 1 p.m. to 5 p.m.
                         Thursday, May 19, 2005 — 8 a.m. to 5 p.m.
                           Friday, May 20, 2005 — 8 a.m. to noon

                                  Hyatt Regency Cincinnati
                                     151 West 5th Street
                                      Cincinnati, Ohio
                          Phone: 513-579-1234 Fax: 513-354-4079

                                               Agenda


1.   Administrative
     a. Welcome and Introductions − Chairman
     b. Arrangements − Secretary
     c. Quorum − Secretary
     d. Procedures − Chairman
        i)      Antitrust Compliance Guidelines
        ii)     Parliamentary Procedures
     e. OC Subcommittee Organization and Procedures – Secretary
     f. Interchange Subcommittee Scope − Secretary
     g. Minutes of February 8–10, 2005 Meeting − Chairman
     h. Approval of Agenda − Chairman                                                   20 minutes


2.   Open Issues — Doug Hils                                                                 1 hour
     a. NERC Operating Manual – Gordon Scott, Doug Hils
        i)      Appendixes
        ii)     Reference documents
        iii)    NAESB business practices
     b. E-tag standard usage – Gordon Scott
     c. Tagging point-to-point schedules within a Balancing Authority – John Simonelli
     d. TISWG chair replacement – Doug Hils

3.   OASIS II Conference — Gordon Scott                                                      1 hour
     a. Industry comments
     b. Future modifications
     c. Registry Comments
                                     A New Jersey Nonprofit Corporation

                         Phone 609-452-8060   Fax 609-452-9550   URL www.nerc.com
 4.    JISWG Report — Gordon Scott                                               1 hour
       a. JISWG scope statement
       b. JISWG structure and function
       c. Registry update
       d. PKI implementation for electronic tagging – Larry Stone

 5.     Current Standards — Larry Goins                                         3 hours
        a. INT Standard – Larry Goins
           i)     Compliance measures
           ii)    Outstanding modifications

 6.     MISO Operations — Doug Hils                                              1 hour
        a. Update on MISO operations since startup on April 1
        b. Day-ahead and real-time issues

 7.     Black Oak Energy Interpretation Request — Doug Hils                      1 hour

 8.     Reference Document Updates — Melinda Montgomery                          4 hour
        a. Dynamic Transfer White Paper
        b. Interchange Reference Document
        c. Waivers – Doug Hils

 9.     Functional Model – IAITF Recommendations — Pat Doran                    2 hours
        a. Review IAFTF recommendations
        b. Assign responsibilities
        c. FMWG May 16–17, 2005 meeting review – Roman Carter
        d. Coordinate Interchange Standard – Mike Oatts

10.     Dynamic Transfer Catalog — Gordon Scott                                  1 hour
        a. Discuss scope statement
        b. Review the data collection form
        c. Request to regions for dynamic transfer catalog data collection

11.     Future Meetings — Secretary                                          10 minutes
        a. Review meeting calendar for 2005




Interchange Subcommittee Meeting Agenda                                               2
May 18–20, 2005
Item 1.         Administrative


a.      Welcome and Introductions − Chairman
The chairman will welcome the group and request introductions.

The subcommittee will review the roster for revisions.

Attachment
Interchange Subcommittee roster

b.      Arrangements − Secretary
The secretary will review the meeting arrangements. The Interchange Subcommittee will convene
on Wednesday, May 18 at 1 p.m. and will adjourn at noon on Friday, May 20. A luncheon will
be served on Thursday.

c.       Quorum − Secretary
The secretary will announce whether a quorum (50% of the voting members) is in place. NOTE:
The subcommittee cannot conduct business without a quorum. Please be prepared to stay for the
entire meeting.

d.      Procedures − Chairman
The NERC Antitrust Compliance Guidelines and a summary of Parliamentary Procedures are
attached for reference. The secretary will answer questions regarding these procedures.

Attachments
•    Antitrust Guidelines
•    Summary of Parliamentary Procedures

e.      OC Subcommittee Organization and Procedures
A summary of OC Subcommittee Organization and Procedures is attached for reference. The
secretary will answer questions regarding these procedures.

Attachment
OC Subcommittee Organization and Procedures

f.      Interchange Subcommittee Scope
The Interchange Subcommittee scope is attached for reference. The secretary will answer
questions regarding the scope.

Attachment
Interchange Subcommittee scope

g.      Minutes of February 8–10, 2005 Meeting − Chairman
The chairman will ask for approval of the February 8–10, 2005 Interchange Subcommittee
meeting minutes.
Attachment
Minutes of February 8–10, 2005 Interchange Subcommittee meeting

h.       Approval of Agenda − Chairman
The chairman will announce agenda changes and ask for additional items from the subcommittee
members.

Action
The chairman will ask for approval of the agenda.
                                   Interchange Subcommittee



Chairman        Douglas E. Hils                  Cinergy Corp.                             (513) 287-2149
                Manager, Control Area            139 East Fourth Street, Room 635-Annex    (513) 287-3812 Fx
                Operations                       Cincinnati, Ohio 45202                    doug.hils@
                                                                                           cinergy.com

Vice Chairman   James G. McIntosh                California ISO                            (916) 351-2101
                Director of Grid Operations      151 Blue Ravine Road                      (916) 351-2453 Fx
                                                 Folsom, California 95630                  jmcintosh@
                                                                                           caiso.com

                Alan Boesch                      Nebraska Public Power District            (402) 845-5210
                Operational Compliance           P.O. Box 1000                             (402) 845-5238 Fx
                Supervisor                       Doniphan, Nebraska 68832-1000             agboesc@nppd.com

                J. Roman Carter                  Southern Company Generation and Energy    (205) 257-4441
                Project Manager, Energy          Marketing                                 (205) 257-4441 Fx
                                                 600 North 18th Street                     jrcarter@
                                                 GS-8259                                   southernco.com
                                                 PO Box 2641
                                                 Birmingham, Alabama 35291

                John Dadourian                   PJM Interconnection, L.L.C.               (610) 666-8959
                Supervisor-Transaction           955 Jefferson Avenue                      (610) 666-4532 Fx
                Coordination, Transmission       Valley Forge Corporate Center             dadouria@pjm.com
                                                 Norristown, Pennsylvania 19403-2497

                Ronald L. Donahey                Tampa Electric Co.                        (813) 623-5120
                Managing Director, Grid          P.O. Box 111                              (813) 630-6299 Fx
                Operations                       Tampa, Florida 33601-0111                 rldonahey@
                                                                                           tecoenergy.com

                Pat Doran                        Independent Electricity System Operator   (905) 855-6233
                Manager-Market Facilitation      Station A                                 (905) 855-6249 Fx
                                                 Box 4474                                  pat.doran@
                                                 Toronto, Ontario M5W 4E5                  ieso.ca

                Joe Gardner                      Midwest ISO, Inc.                         (317) 249-5446
                Director, Real-Time Operations   701 City Center Drive                     (317) 249-5910 Fx
                                                 Carmel, Indiana 46032                     jgardner@
                                                                                           midwestiso.org

                James Michael Hansen             Seattle City Light                        (206) 706-0165
                Strategic Advisor                614 NW 46th Street                        (206) 706-0183 Fx
                                                 Seattle, Washington 98107                 james.hansen@
                                                                                           seattle.gov

                Frederick J. Kunkel              Wabash Valley Power Association           (317) 481-2846
                Manager Transmission Services    722 North High School Road                (317) 243-6416 Fx
                                                 Indianapolis, Indiana 46214-3756          fredk@wvpa.com

                Donald P. Lacen                  Public Service Company of New Mexico      (505) 241-2032
                Transmission Services            Alvarado Square, MS-EP11                  (505) 241-2582 Fx
                Coordinator                      Albuquerque, New Mexico 87158             dlacen@pnm.com
              Melinda K. Montgomery            Entergy Services, Inc.                        (870) 541-4578
              Transmission Business Manager,   5201 West Barraque                            (870) 541-3964 Fx
              Operations                       Pine Bluff, Arkansas 71602                    mmontg3@
                                                                                             entergy.com

              Michael L. Oatts                 Southern Company Services, Inc.               (205) 257-7743
              Manager, EMS Applications        14N-8220                                      (205) 257-5083 Fx
                                               P.O. Box 2641                                 mloatts@
                                               Birmingham, Alabama 35202-2625                southernco.com

              Deanna M. Phillips               Bonneville Power Administration               (503) 230-5164
              Senior Electrical Engineer       Routing PGS                                   (503) 230-5054 Fx
                                               P.O. Box 3621                                 dmphillips@
                                               Portland, Oregon 97208                        bpa.gov

              Timothy E. Ponseti               Tennessee Valley Authority                    (423) 751-2699
              General Manager, Transmission    1101 Market Street, MR-3H                     (423) 751-8352 Fx
              Policy Development               Chattanooga, Tennessee 37402                  teponseti@
                                                                                             tva.gov

              John M. Simonelli                ISO New England, Inc.                         (413) 535-4157
              Manager Tariff, Schedules &      One Sullivan Road                             (413) 535-4343 Fx
              OASIS                            Holyoke, Massachusetts 01040-2841             jsimonelli@
                                                                                             iso-ne.com

TISWG Chair   Monroe J. Landrum, Jr.           Southern Company Services, Inc.               (205) 257-6936
              Manager, Operating Systems       600 North 18th Street                         (205) 257-6663 Fx
              Bulk Power Operations            P.O. Box 2641                                 mjlandru@
                                               Birmingham, Alabama 35291-8210                southernco.com

NERC Staff    William D. Blevins               North American Electric Reliability Council   (609) 452-8060
Coordinator   Manager of Interchange           116-390 Village Boulevard                     (609) 452-9550 Fx
                                               Princeton, New Jersey 08540-5731              bill.blevins@
                                                                                             nerc.net
         NORTH AMERICAN ELECTRIC RELIABILITY COUNCIL
         Princeton Forrestal Village, 116-390 Village Boulevard, Princeton, New Jersey 08540-5731



                          NERC ANTITRUST COMPLIANCE GUIDELINES


I.   GENERAL

It is NERC’s policy and practice to obey the antitrust laws and to avoid all conduct that unreasonably
restrains competition. This policy requires the avoidance of any conduct that violates, or which 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.

Approved by NERC Board of Trustees
June 14, 2002

                       Phone 609-452-8060 + Fax 609-452-9550 + URL www.nerc.com
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 and Bylaws are followed in conducting NERC business. Other NERC procedures that may
be applicable to a particular NERC activity include the following:

    •   Organization Standards Process Manual
    •   Transitional Process for Revising Existing NERC Operating Policies and Planning Standards
    •   Organization and Procedures Manual for the NERC Standing Committees
    •   System Operator Certification Program

In addition, all discussions in NERC meetings and other NERC-related communications should be within
the scope of 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 inf luenced 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.

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




Approved by NERC Board of Trustees
June 14, 2002                                                                                              2
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           Move                Yes             The main action that begins a debate.
discussion
Revise a Motion currently    Amend               Yes             Takes precedence over discussion of main motion.
under discussion                                                 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          Reconsider          Yes             Allowed only by member who voted on the
already approved                                                 prevailing side of the original motion.
End debate                   Call for the        Yes             If the Chair senses that the committee is ready to
                             Question or End                     vote, he may say “if there are no objections, we will
                             Debate                              now vote on the Motion.” Otherwise, this motion is
                                                                 debatable and subject to 2/3 majority approval.
Record each member’s         Request a Roll      No              Takes precedence over main motion. No debate
vote on a Motion             Call Vote                           allowed, but the members must approve by 2/3
                                                                 majority.
Postpone discussion until    Lay on the Table    Yes             Takes precedence over main motion. Used only to
later in the meeting                                             postpone discussion until later in the meeting.
Postpone discussion until    Postpone until      Yes             Takes precedence over main motion. Debatable
a future date                                                    only regarding the date (and time) at which to bring
                                                                 the Motion back for further discussion.
Remove the motion for any    Postpone            Yes             Takes precedence over main motion. Debate can
further consideration        indefinitely                        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          Point of order      No              Second not required. The Chair or secretary shall
procedure                                                        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.
Voting
Voting Method                   When Used                                      How Recorded in Minutes
Unanimous Consent               When the Chair senses that the Committee       The minutes show “by unanimous
                                is substantially in agreement, and the         consent.”
                                Motion needed little or no debate. No actual
                                vote is taken.
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     The minutes show both vote totals,
                                when an issue has engendered substantial       and then Approved or Not Approved
                                debate or appears to be divisive. Also used    (or Failed).
                                when a Voice Vote is inconclusive. (The
                                Chair should ask for a Vote by Show of
                                Hands when requested by a member).
Vote by Roll Call               To record each member’s vote. Each             The minutes will include the list of
                                member is called upon by the Secretary,,       members, how each voted or
                                and the member indicates either “Yes,”         abstained, and the vote totals. Those
                                “No,” or “Present” if abstaining.              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.
                                                                                          Approved by Operating
                                                                                          Committee
                                                                                          July 11–12, 2001
OC Subcommittee
Organization and Procedures

Introduction
This document explains the membership requirements and selection procedure
for the Operating Committee’s Subcommittees. Membership on Task Forces and
Working Groups will remain as specified in the Standing Committees
Organization and Procedures Manual, Section VI.
Background
NERC has very specific membership requirements for its Standing Committees
to ensure that all industry segments as well as the Regional Councils are
represented. However, subcommittees, task forces, and working group
membership may be based on either “expertise” (with varying degrees of regard
to industry segments) or on industry segments (with some regard to expertise), at
the discretion of the parent Committee.
In reality, most Operating Committee subgroup members represent the Regional
Councils, with emphasis on expertise in the subgroup’s areas of responsibilities,
and with some or little regard to industry segment representation. This may be
acceptable for the membership of task forces and working groups. However, the
Operating Committee’s subcommittees have Operating Policy custodianship;
therefore, subcommittee membership must encompass the various industry
segments who are materially affected by the Operating Policies for which the
subcommittee is responsible. This is in addition to the traditional Regional
Council representation, which should continue.
Subcommittee Scope and Reporting
The Subcommittee will keep its Scope Document up to date. All Subcommittees
report to the Operating Committee.

Operating Policies
The Subcommittee will follow NERC’s Policy and Standards Development
Process when posting new or revised Operating Policies for comment or
Operating Committee ballot. The Subcommittee will respond to all public
comments. The Subcommittee may request Operating Committee input and
advice when preparing new or revised Operating Policies, but does not need
Operating Committee approval to post Policies for comment or OC ballot.
Membership Criteria
The Resource, Transmission, Interchange, Security, and Interconnected
Operations Services, Subcommittees shall comprise 19 members: nine system
operators or transmission providers, nine transmission customers, plus a
chairman who does not represent any industry segment or Regional Council.
The Personnel Subcommittee’s primary focus is on System Operator training and             The Personnel
certification and its membership should include expertise in these two areas.             Subcommittee is a bit
                                                                                          different.
Regional Council training managers should be on the Personnel Subcommittee.
The Subcommittee should also strive for participation from transmission
customers, but an equal mix of operators and customers may not be feasible.


                                               -1-                                  Approved by NERC OC
                                                                                         July 11−12, 2001
OC Subcommittee Organization and Procedures


Furthermore, all Subcommittees shall include among their 18 members:
    •   At least one representative from each Interconnection.
    •   At least one representative from Canada

Expertise
Expertise in the subject of the Operating Policies for which the Subcommittee is
responsible remains of prime importance.

Regional Council Representation
NERC’s underpinnings remain the Regional Councils, and they have expressed a
strong desire to continue to be represented on NERC Subcommittees. Therefore,
Subcommittee membership must accommodate representatives from each of the
10 Regional Councils (if they desire such representation). This representation
should be embodied in the Subcommittee 18 members.

Members from the same organization                                                     Current practice. Less
                                                                                       restrictive than Standing
Two subcommittee members may be from the same organization as long as one              Committees, but increases
is a system operator or transmission provider and the other a transmission             pool of experts to select
customer.                                                                              from.


Members on multiple Subcommittees                                                      Current practice. In some
Individuals should not serve on more than one Subcommittee if possible.                cases, we have no choice.

Officers
The Subcommittee will have a chairman and a vice chairman. The chairman will
not represent either the provider or customer segment, or a Regional Council.
The Subcommittee vice chairman will be one of the 18 members, preferably from
a different industry segment than the chairman.
Membership Selection
To fill a Subcommittee vacancy:
    1. The NERC staff will solicit candidates from the Subcommittee officers,
       Standing Committee members, Regional Councils, and Trade
       Organizations as necessary.
    2. The Subcommittee chairman will then select from that list sufficient
       candidates to fill the vacancies, keeping in mind the segment balance that
       must be maintained on the Subcommittee.
    3. The NERC staff will send the recommended candidates to the Operating
       Committee chairman via e-mail for approval. The e-mail will include a
       brief biography of the candidate and current responsibilities. The staff
       will copy the OC and MIC Executive Committees for their comments.
    4. The Operating Committee chairman will consider the comments offered
       by the Executive Committees and issue his decision within five days of
       the request.



                                              -2-                                  Approved by NERC OC
                                                                                        July 11−12, 2001
OC Subcommittee Organization and Procedures


Officer Selection
The NERC staff will solicit candidates from the Subcommittee officers, Standing
Committee members, Regional Councils, and Trade Organizations as necessary.
The Subcommittee officers will then be selected jointly by the Operating
Committee and Market Interface Committee chairmen.
Meeting Procedures

Quorum
A quorum consists of 50% of the Subcommittee members listed on the current
roster.

Voting
A two-thirds vote is required to adopt any motion. A two-thirds vote is based on
the total votes cast. Abstentions are neither requested nor considered in
calculating the two-thirds vote.
Subgroups
The Subcommittee may form Task Forces and Working Groups as necessary.
The Subcommittees may also form small Task Groups to assist in drafting
Standards, processes, Reference Documents, and concept papers between regular
Subcommittee meetings. These Task Groups would, in most cases, exist for a
short time (usually less than a year), and report to the Subcommittee. (Task
Forces and Working Groups may also form Task Groups for this purpose).
Open Meetings
Subcommittee meetings will be open to guests who register in advance.
Subcommittee chairmen will ensure that guests have an opportunity to participate
in the discussion. However, voting will be the responsibility of the Subcommittee
members only.




                                              -3-                                  Approved by NERC OC
                                                                                        July 11−12, 2001
Scope
Interchange Subcommittee


Purpose
The Interchange Subcommittee develops, maintains, and oversees the implementation of Policies and
Standards that provide for the movement of energy across the transmission network in a reliable and
efficient manner.

Scope
The Interchange Subcommittee develops, maintains and oversees the implementation of the Policies,
Standards and compliance requirements specifically related to:

    1. Market requests to implement and/or modify physical transactions
    2. Reliability requests to modify physical transactions
    3. Implementation of the above requests as schedules.

The Interchange Subcommittee will also:

   1.   Assist in developing programs and facilities associated with the transfer of energy. This includes
        development of the business plan, including costs, and schedules for developing system projects
        and training.
    2. Develop Metrics and Compliance Templates for performance measurement.
   3. Assist the Personnel Subcommittee in developing training materials for system operators.

Operating Policies
    1. Policy 3 “Interchange” and its Appendixes.
    2. Responsible for policies and standards involving interchange.

Reporting
The Interchange Subcommittee reports to the NERC Operating Committee and shall maintain
communications with the Market Interface Committee, Planning Committee, and other groups as
necessary on relevant issues.

Membership
    1. Eighteen members plus chairman.
    2. Membership is divided equally between transmission providers/system operators and
       transmission customers.

Officers
Chairman and vice chairman, selected by the Operating Committee chairman and vice chairman. The
chairman does not represent an industry sector. Both officers may vote.

Meeting Procedures
    1. Quorum: 50% of Subcommittee members eligible to vote.
    2. All other procedures follow those of the “Organization and Procedures Manual for the NERC
       Standing Committees.”

                                              -1-                                      Approved by OC:
                                                                                         March 29, 2001
Subgroups
The Interchange Subcommittee may form Working Groups, Task Groups, and Task Forces as needed to
assist the Subcommittee in carrying out standing or ad hoc assignments. Task Group chairmen (or
delegates) are expected to attend the regular Subcommittee meetings to report on assignments.

    1. Transaction Information System Working Group. Responsible for implementing NERC
       transaction information system. (See TISWG Scope.)




                                           -2-                                 Approved by OC:
                                                                                 March 29, 2001
        NORTH AMERICAN                  ELECTRIC RELIABILITY COUNCIL
        Princeton Forrestal Village, 116-390 Village Boulevard, Princeton, New Jersey 08540-5731




                          Interchange Subcommittee Meeting
                                          February 8–10, 2005
                                           Phoenix, Arizona

                                                Minutes
A regular meeting of the Interchange Subcommittee was held on February 8–10, 2005 in Phoenix,
Arizona. The meeting notice, agenda, and attendance list are affixed as Exhibits A, B, and C,
respectively. Individual statements and minority opinions are affixed as Exhibits D and E. (There were
none.)

Introductions
Doug Hils chaired the meeting on February 8 and the morning of February 9. Jim McIntosh chaired the
meeting the afternoon of February 9 and February 10. Bill Blevins, the new NERC facilitator for the
Interchange Subcommittee, was introduced. The subcommittee members and guests introduced
themselves and described their job functions. The secretary reported that a quorum was present.

The chairman summarized the NERC Antitrust Compliance Guidelines, which were included in the
agenda.

The minutes of the November 30, December 1–2, 2004 meeting were approved.

WECC and Unit Contingent Sales
Jim Hansen discussed the E-Tagging unit contingent power. Currently in WECC, and possibly other
NERC regional reliability councils, there is a problem caused by source/sink misunderstanding of who
has reserve carrying responsibilities on some interchange transactions. While most transactions result in
the source and sink understanding and implementing appropriate reserves, there are some instances where
both or neither are carrying reserves. WECC believes this is a reliability problem since the region is not
assured to be carrying the minimum operating reserve levels necessary to assure reliability. This problem
became more frequent as PSEs and LSEs started conducting unit contingent transactions.

    •    The WECC Contingency Reserve Identification Task Force has been asked to resolve the reserve
         issue by creating a new E-Tag that identifies reserve-carrying responsibility. The element would
         flag the source and sink obligation of the E-Tag reserve requirements and responsibility. Doug
         Hils noted that if the solution requires an E-Tag revision, a more universal change that applies to
         other Interconnections would be practical.




                                      A New Jersey Nonprofit Corporation

                          Phone 609-452-8060   Fax 609-452-9550   URL www.nerc.com
Discussion:

    •   IS should discuss this item again to determine if this revision could apply to the other
        Interconnections.
    •   This item could be handled with the product fields.
    •   This item has commercial implications and should be discussed with NAESB.
    •   The WECC should ensure that the definitions for the products is understood in the WECC.

Action: Jim Hansen will bring this issue to the TISWG and ITS at their next meeting. The TISWG
should report to the Interchange Subcommittee at the May 2005 meeting.

Timing for E-Tagging Emergency Transactions – Reliability Standard
Interpretation
Doug Hils led the discussion on E-Tagging Dynamic Schedule and Reserve Schedules and the 60-minute
tagging issue. Mr. Hils asked the committee if there was a need to have some form of accounting
mechanism for post-disturbance analysis purposes. The subcommittee determined that an opinion letter
was needed to explain the 60-minute requirement as stated in the interchange standard.

Action: Jim Hansen will draft an opinion letter that the IS will approve, and then send to the industry
before April 1, 2005. The IS will draft and submit a SAR clarifying INT-001 R2.2.

Interchange Authority Function
Mike Oatts reported on the February 2005 Functional Model Reliability Standards Coordination Task
Force (FMRSCTF) meeting. The FMRSCTF discussed:

    •    The effects of deferring the IA function.
    •    A wide area vs. a local Reliability Authority.
    •    Removing the interchange approval for RA and moving it to Transmission Operator.
    •    The fact that that the IA function does exist in the Version 0 Standards and is assigned to the sink
         BA.

The FMRSCTF requests the subcommittee to provide recommendations on changes to the Functional
Model for “IA-lite.”

Action:
Form a task force to list the IA tasks in the functional model and map those tasks to the current reliability
standards. Members are: Alan Boesch; Melinda Montgomery; Roman Carter; Larry Goins; Pat Doran –
chairman.

The task force should review the task and determine responsible parties prior to the FMRSCTF meeting
on February 23–24, 2005, and develop recommendations for the Interchange Authority.

Version 1 Standards
Mike Oatts provided an overview of the Coordinate Interchange Standard Drafting Team’s work. The
Coordinate Interchange Version 1 timing requirement was changed to be more standard so similar timing
between Interconnections would exist.

Alan Boesch reviewed comments from the Interchange Authority Report posting. The RTOs recommend
an Interchange Authority cost-benefit analysis for the paper’s short-term and long-term recommendations.


Interchange Subcommittee Meeting Minutes                                                                    2
February 8–10, 2005
Phoenix, Arizona
Operating Manual
Don Benjamin reported that the current Operating Manual policies would be replaced with the recently
approved reliability standards that will be implemented on April 1, 2005. Mr. Benjamin requested that the
subcommittees update the reference documents and add those updates to the operating manual. NERC is
working with NAESB to add business practices to the manual.

Dave Hilt informed the subcommittee that compliance measures and levels were transferred from the
templates into the reliability standards. If additional measures are needed in the INT Standards the
Certification Compliance Committee would look to the IS to assist in identifying those measures and
compliance levels. A SAR would be required to add measures and levels of compliance.

The subcommittee formed the Interchange Reference Document Revisions Group (IRDRG) to review the
reference documents. Members are: Melinda Montgomery — chairman; Don Lacen; John Simonelli;
John Dadourian; Roman Carter.

The subcommittee formed the Interchange Standards Revision Group (ISRG) to draft SARs for the INT
reliability standards. Members are: Alan Boesch — chairman; Fred Kunkel; Ron Donahey; Larry Goins
The group’s scope includes revising the INT standards based on industry comments that the IS reviewed
and drafting compliance measures and levels.

The subcommittee formed the Interchange Waiver Revisions Group (IWRG) to revise the waivers in
accordance with the Version 0 Standards. Members are: Doug Hils — chairman; Don Lacen; Jim
Hansen; Joe Gardner.

Dynamic Schedule Working Group Report
The Interchange Subcommittee met with the Operating Reliability Subcommittee to discuss this agenda
topic. Doug Hils, chairman of the Dynamic Schedule Task Force, reviewed the two motions approved by
the IS at its last meeting. At its recent meeting, the IS approved a letter to the industry regarding the
implementation of IS motion one, which is:

    Motion One — For a dynamic schedule, the entity creating the E-Tag for the schedule must indicate
    that the E-Tag is of the type “Dynamic” (<Transaction Type>Dynamic</Transaction Type>). The
    type “Dynamic” on the E-Tag must not be used when a schedule is not a dynamic schedule.

Mr. Hils noted that Motion Two (Part A) is addressed by implementation of IDC change order 179 (Firm
Dynamic Transaction Handling in TLR Levels 1–4). Part A of Motion 2 is:

    Motion Two (Part A) — Short Term — If the E-Tag is identified as the type “Dynamic,” and the
    transmission service is considered firm according to the constrained path method, then it will not be
    held by the IDC during TLR level 4 or lower.

The IS drafted a revision to reliability standard IRO-006-0, Requirement 1.6.6 of Attachment 1, which
could be processed as an urgent action SAR. Mr. Hils stated that the ORS should decide if this is a
standards change or a standards interpretation.

Lanny Nickell expressed concern related to the potential reliability impacts of changing dynamic
schedules, especially those of significant magnitude. He suggested that the IDCWG consider the
reliability impacts, and consider changing the IDC to provide as much information as possible to the
reliability coordinator regarding changing dynamic schedules. IDCWG Chairman Julie Pierce noted that
some dynamic schedules are tagged after-the-fact. ORS Chairman Roger Harszy requested the addition
of alarming, reliability coordinator notification, and viewing capability be added to IDC CO-179.


Interchange Subcommittee Meeting Minutes                                                                    3
February 8–10, 2005
Phoenix, Arizona
Julie Pierce stated that a revised IDC CO-179 could probably be implemented by June 1, 2005. Garth
Arnott suggested pursuing an interpretation of standard IRO-006-0 to quickly incorporate the changes the
IS had made to IRO-006-0. Don Benjamin noted that there is a formal standards interpretation process
that should be followed.

Lanny Nickell moved to accept the changes proposed to IRO-006-0, Attachment 1, as approved by the IS,
and to request the Dynamic Schedules Task Force to develop an urgent action standards authorization
request (SAR) to modify Attachment 1 to standard IRO-006-0 and to submit the SAR to the standards
process manager. Anthony Jankowski seconded the motion. The ORS approved the motion.

The Dynamic Schedules Task Force will draft an urgent action SAR, and submit it to the IS and ORS for
approval. The ORS requested that the IDCWG not begin implementation of IDC CO-179 until directed
to do so by the ORS.

Dynamic Transfer Catalog
The subcommittee agreed to move forward on developing the Dynamic Transfer Catalog. The
subcommittee requested that the Dynamic Transfer Working Group review the following issues:

    •   FRCC’s Operating Reliability Subcommittee’s difficulty in understanding the definition of a
        Pseudo-Tie as explained in the DTWG’s paper.

    •   The need to define “contiguous” as it relates to Actual Ties and Pseudo-ties.

Action: The subcommittee will draft a letter requesting the regions ensure that dynamic transfers are
properly identified and modeled. The subcommittee will draft a project plan to ensure data is submitted in
a standard format.

TISWG Report
Gordon Scott provided an update on the proposed formation of a joint NERC and NAESB technical
group to address business practices and reliability issues regarding interchange. The group would
encompass the NERC TISWG and the NAESB ITS and ESS, and would take on a much larger role in
determining the future of the TISN Registry and OASIS.

NERC and NAESB plan to conduct a “Future of OASIS Conference” on March 29. 2005. The
conference will help determine the future of OASIS II.

Other Items

EPRI Transfer Analysis
Bob Cummings reviewed EPRI’s current analysis of north-to-south transfers for the Eastern
Interconnection from 2000 to 2004.

Standard Energy Day
The subcommittee reviewed the NERC/NAESB work on standardizing the energy day and determined the
IS did not need to comment.


Bill Blevins
Secretary
Interchange Subcommittee


Interchange Subcommittee Meeting Minutes                                                                 4
February 8–10, 2005
Phoenix, Arizona
Item 2.         Open Issues
Background
Gordon Scott will lead a discussion on the NERC Operating Manual appendixes, reference
documents, and NAESB business practices.

Mr. Scott will also discuss a motion by the Joint Interchange Scheduling Working Group
(JISWG) on the usage of the term “E-tag.”

John Simonelli will lead a discussion on tagging point-to-point schedules within a balancing
authority.

Doug Hils will discuss the replacement of the TISWG chairman.

Actions
1. Provide guidance on the tagging point-to-point schedule discussion.

2. Develop a timeline for replacing the TISWG chairman.

Attachments
•   Operating Manual located on the NERC website http://www.nerc.com/~oc/opermanl2.html

•   Summary – Tagging Point-to-Point Schedules within a BA
Tagging Point-to-Point Schedules within a Balancing Authority

A description on the issues that John Simonelli raised with the IS follows. Hopefully this summary will be
sufficient to provide background on the issues at hand. Mike Zeoli and I will be present at the IS meeting
to discuss these issues further.

ISO New England administers a broad regional tariff. Our tariff covers the majority of the bulk
transmission facilities within New England, however it does not cover all facilities. Specifically it does not
cover low voltage systems (69 KV and below), radial lines to generators regardless of voltage class and,
certain non-regional facilities (HVDC tie to Québec, AC tie line to New Brunswick and HVDC tie to Long
Island).

The standard that we would like for IS to review is Requirement 1.2 in standard INT-001-0:

R1. The Load-serving Purchasing-Selling Entity shall be responsible for ensuring Tags are submitted for:

  R1.1. All Interchange Transactions that are between Balancing Authority Areas

  R1.2. All transfers that are entirely within a Balancing Authority Area using Point-to-Point Transmission
Service (including all grandfathered and “non-

       Order 888” Point-to-Point Transmission Service).

R1.3. All Dynamic Schedules at the expected average MW profile for each hour.

During a discussion with one of the Transmission Owners (TO) in New England, the ISO NE was
informed that there have been a number of internal Point to Point arrangements utilized by the TOs that
currently are not tagged and do not affect inter control areas transfers.

The first issue we came across is where one New England Transmission Owner sells Local Point to Point
transmission service to small IPPs that are utilizing transmission lines of 69 kV or less. The generators
must use these smaller local lines in order to reach the 115 kV of our grid. Similar generators that are
directly connected to the higher 115 kV lines (administered by the Regional Pool tariff by offering RNS-
Regional Network Service) do not have to purchase local Point to Point service and they are never
tagged. However, by reading the current standard it appears that these several small IPP generators (10
to 40 MW), which must use local point-to-point service (where RNS is not offered) are required to
tag these internal transactions that ultimately are serving the same system load as the other
generators. From ISO New England's point of view it doesn't seem to make sense to tag these
transactions that are on small lines 69kv and bellow. We would like for the IS to consider whether there
should be some provision in Standard INT-001-0 exempting either point-to-point transactions under a
certain voltage level or local Point to Point usage that does not impact inter control areas interchange
totals.

The second issue we have is regarding our tie line with New Brunswick. It is a single 345 KV line with
two 345 to 115 KV substations. This line is not covered under our RTO tariff but falls under the OATT of
Maine Electric Power Company. The Transmission Operator has sold internal point-to-point
transmission service that is actually bridged from one substation to another. This transmission service
provides the adequate transmission for a certain generator that is now dispatched by the ISO's Control
Room to serve New England’s system load. These type of generators serve our system
load by receiving dispatch instructions every 10 minutes or so according to the economic and reliability
conditions. It becomes extremely tedious and at times almost impossible with the current tagging system
to follow multiple schedule changes during the hour. We request the IS to consider our example and grant
us exemption from tagging transactions that serve our system load.
Item 3.        OASIS II Conference
Background
Gordon Scott will report on the OASIS II Conference, industry feedback, future OASIS
incremental modifications, and feedback on the TSIN registry.

Attachment
Letter – Michehl R. Gent to Rae McQuade – Results from the NERC-NAESB OASIS Conference,
dated April 22, 2005
                NORTH AMERICAN                                        NORTH AMERICAN
                ELECTRIC RELIABILITY                                  ENERGY STANDARDS
                COUNCIL                                               BOARD

                                                                                    Via email and post
                                                                                        April 22, 2005

The Honorable Patrick H. Wood III
Chairman
Federal Energy Regulatory Commission
888 First Street N.E.
Washington, D.C. 20585

RE:       Results from the NERC-NAESB OASIS Conference held March 29, 2005

Dear Mr. Chairman:
    NAESB and NERC held a very productive meeting on March 29 regarding the industry
perspectives on the future of OASIS. The turnout was better than we expected, both for attendance
in the room and on the phone, with representation from all industry segments. We had several
presentations that set the stage for open and candid industry discussion. Your office played a large
role in this meeting’s success, by providing the meeting facilities at FERC and through the
participation of Marvin Rosenberg of your staff.
      We draw two key conclusions from the meeting:
      •   The industry has embraced electronic scheduling as an efficient market tool. Through the
          implementation of e-tags and the incorporation of e-tags into organizations’ scheduling
          systems, the industy is in the midst of a migration towards electronic scheduling today
          without the need for a major redefinition of OASIS requirements.
      •   The changes to OASIS to better support the market are being done on an incremental basis
          as the industry determines those changes are needed and can prioritize and staff the
          standards development work. NAESB has several enhancements in front of you with the
          January 2005 NAESB filing (Docket No. RM05-5-000 included OASIS enhancements for
          redirects and multiple requests as well as minor changes to existing OASIS standards). More
          enhancements are being developed or planned (resales and transfers of transmission rights,
          capacity release rights needed to implement redirect business practices, enhancements to the
          registry, publish/subscribe functions, standardized process for NITS service, naming
          standardization). Several other suggestions for standards development were made during the
          meeting and will be pursued by NAESB through a development of a standards request.
          Working with NAESB, NERC will continue to maintain and improve the TSIN registry.
   Because of the points noted above, the group determined that this was an effective and efficient
way to move forward and adapt OASIS to market needs. There was no dissent by any of the
participants in taking this incremental approach. As such, NAESB will continue in the direction of
making changes in an evolutionary fashion, request by request, and packaging those changes into a
work product to submit to the FERC as they are adopted. NERC will continue its support for OASIS
matters related to reliability.
    We truly appreciate Mr. Rosenberg’s involvement and doubt that we could have had the
attendance and interest in this topic without your willingness to host the meeting at FERC’s offices.
Many other points were made during the meeting and for more details on the discussion the minutes
and the list of attendees are posted on the NAESB web site.1 Also, transcripts are available from the
meeting.2

1 The presentations and minutes of the March 29 joint NERC-NAESB meeting may be found at the NAESB web
site on the following page: http://www.naesb.org/weq/weq_ess_oasis_2.asp
2 For the transcripts, please contact the NAESB office for information.
            NORTH AMERICAN                                     NORTH AMERICAN
            ELECTRIC RELIABILITY                               ENERGY STANDARDS
            COUNCIL                                            BOARD

                                                                                    April 22, 2005
                                                                                       Page 2 of 2


    Both NERC and NAESB will continue to work together to develop standards for the betterment of
the market and the reliability of the system. For OASIS, we will continue to work on requests for
enhancements and modifications as submitted from the industry. This was a very productive
meeting and we again thank you for helping us make it so.


With Best Regards,

Rae McQuade                                      Mike Gent
Rae McQuade                                      Michehl R. Gent
President                                        President
North American Energy Standards Board            North American Electric Reliability Council

1301 Fannin Street, Suite 2350                   116-390 Village Blvd.
Houston, Texas, 77002                            Princeton, New Jersey 08540-5731
(713) 356-0060                                   (609) 452-8060
Item 4.         Joint Interchange Scheduling Working Group Report
Background
Gordon Scott will discuss the actions from the May JISWG meeting. The JISWG requests that the
Interchange Subcommittee review and comment on the JISWG scope and mission statement. Mr.
Scott will discuss the JISWG structure and reporting responsibility. He will also request that
RTOs participate at the JISWG meetings, and inform the IS of upcoming JISWG meetings.



Attachments
•   Joint Interchange Scheduling Working Group scope

•   Registry business practice request

•   PKI implementation Plan
          NERC/NAESB Joint Interchange Scheduling Workinging Group
                        Mission and ScopeStatement


Purpose
The Joint Interchange Scheduling Working Group (JISWG) will address joint issues
within the scope of the NAESB Wholesale Electric Quadrant (WEQ) Information
Technology Subcommittee (ITS) and the NERC Interchange Subcommittee (IS) due to
the interdependency of commercial and reliability activities between NAESB and NERC.
Joint Interchange Scheduling Working Group (JISWG) is the NERC/NAESB combined
working group formed to develop technical standards and communication protocols for
Open Access Same-Time Information Systems (OASIS), e-tagging and Transmission
Services Information Network (TSIN) Registry and to develop Cyber-security standards
for OASIS and NERC e-tagging. It was developed to work on issues remanded to it from
the NAESB WEQ EC and NERC IS due to the interdependency of these of specific
activites between NERC and NAESB. Specifically the JISWG will assist the NAESB
WEQ Information Technology Subcommittee (ITS) and the NERC Transaction
Information System Working Group (TISWG) in the following areas:

Scope of Activities
   • Coordinatinge the development of technical standards and communication
       protocols for including aspects of Open Access Same-Time Information Systems
       (OASIS) and e-tagging in support of NERC Interchange standards and NAESB
       business practices.
   • Developing Cyberapplication -security standards for OASIS and NERC e-
       tagging.
   • Servinge as a common point of contact for all industry organizations to propose
       additions and enhancements to the Transmission Services Information Network
       (TSIN) Registry.
   • Developing and revisinge System Requirements Specification (SRS)Documents
       as required to specify system functional requirements. for the TSIN Registry.
   • Project Mmanagingement responsibilities for the development, implementation,
       and oversight of technical projects of the TSIN Registry as assigned by the
       NAESB WEQ ITS and NERC Transaction Information System Working Group
       (TISWG) or as appropriate within the JISWG scope..


Reporting
The JISWG reports to the NAESB WEQ ITS and NERC TISWG. Interchange
Subcommittee.

The (JISWG) shall work in closely with all industry organizations that require or rely on
the TSIN Registry, OASIS and e-tagging (e.g., ISO/RTO Council, NERC IDCWG,
NERC IS, NAESB WEQ ITS etc.).
Leadership, Membership and Conducting Business
Co-chairs will lead the Joint (JISWG) Group – one chairman to representfrom the NERC
TISWG and one chairman to representfrom the NAESB WEQ. WEQ ITS. Membership
and meeting attendance is open to any industry participant regardless of affiliation.
NERC and NAESB staffs and the JISWG co-chairsrman on the working group will work
jointly on meeting agendas and the scheduling of meetings.

Meetings
The (JISWG) group will conduct meetings as necessary. All meeting announcements,
agendas, working papers, etc., will be distributed via e-mail and posted for public notice
on the NAESB and NERC websites.
                                         R04037
        Request for Initiation of a NAESB Standard for Electronic Business Transactions or
       Request for Enhancement of a NAESB Standard for Electronic Business Transactions
                                                                                   Page 1

                           North American Energy Standards Board


 Request for Initiation of a NAESB Business Practice Standard, Model Business Practice or
                                  Electronic Transaction
                                            or
Enhancement of an Existing NAESB Business Practice Standard, Model Business Practice or
                                  Electronic Transaction


Instructions:

       1.       Please fill out as much of the requested information as possible. It is
                mandatory to provide a contact name, phone number and fax number to
                which questions can be directed. If you have an electronic mailing address,
                please make that available as well.


       2.       Attach any information you believe is related to the request. The more
                complete your request is, the less time is required to review it.

       3.       Once completed, send your request to:
                      Rae McQuade
                      NAESB, Executive Director
                      1301 Fannin, Suite 2350
                      Houston, TX 77002

                      Phone: 713-356-0060
                      Fax:   713-356-0067

                by either mail, fax, or to NAESB’s email address, naesb@aol.com

Once received, the request will be routed to the appropriate subcommittees for review.


 Please note that submitters should provide the requests to the NAESB office in sufficient
   time so that the NAESB Triage Subcommittee may fully consider the request prior to
     taking action on it. It is preferable that the request be submitted a minimum of 3
 business days prior to the Triage Subcommittee meetings. Those meeting schedules are
       posted on the NAESB web site at http://www.naesb.org/monthly_calendar.asp.
                                         R04037
        Request for Initiation of a NAESB Standard for Electronic Business Transactions or
       Request for Enhancement of a NAESB Standard for Electronic Business Transactions
                                                                                   Page 2

                          North American Energy Standards Board

 Request for Initiation of a NAESB Business Practice Standard, Model Business Practice or
                                  Electronic Transaction
                                            or
Enhancement of an Existing NAESB Business Practice Standard, Model Business Practice or
                                  Electronic Transaction


                                                       Date of Request: November 18, 2004


1. Submitting Entity & Address:
                            North American Energy Standards Board
                            Wholesale Electric Quadrant
                            Information Technology Subcommittee
                            1301 Fannin, Suite 2350
                            Houston, TX 77002


2. Contact Person, Phone #, Fax #, Electronic Mailing Address:
                            Name :         Paul R. Sorenson for the WEQ ITS
                            Title :        Manager, Central Markets Strategy
                                           Open Access Technology International, Inc.
                            Phone :        612-360-1633
                            Fax    :       763-553-2813
                            E-mail :       paul.sorenson@oati.net


3. Description of Proposed Standard or Enhancement:
                                   Revise the basic structure and enhance the capabilities of
                                   the NERC Registry, for the registration of critical
                                   information needed by the WEQ for OASIS enhancements.
                                   This activity will require the close interaction and
                                   involvement of the NERC TISWG and NAESB WEQ ITS in
                                   order to effectively support the requirements for NERC
                                   and NAESB Version 1 Coordinate Interchange Standards
                                   and Business Practices. This work will also lay the
                                   framework for supporting Cyber-security standards for
                                   OASIS and NERC E-Tagging, and enabling future
                                   extensions necessary for OASIS enhancements.
                                   It is expected that the final work product will be a
                                   registry specification and related supporting documents.
                                         R04037
        Request for Initiation of a NAESB Standard for Electronic Business Transactions or
       Request for Enhancement of a NAESB Standard for Electronic Business Transactions
                                                                                   Page 3



4. Use of Proposed Standard or Enhancement (include how the standard will be used,
   documentation on the description of the proposed standard, any existing documentation
   of the proposed standard, and required communication protocols):
                                   The NERC Registry currently supports the Industry’s
                                   registration of key information dictated in the OASIS
                                   technical standards as well as information critical to
                                   support NERC’s Electronic Tagging specification. This
                                   registry is being revised by NERC in anticipation of the
                                   registration of business entities performing key functions
                                   specified in the NERC Functional Model.
                                   The registry will require additional work beyond this
                                   initial enhancement as part of the Version 1 Standards
                                   development, particularly related to the Coordinate
                                   Interchange standards and the registration of entities
                                   qualifying to perform the Interchange Authority function.
                                   Further, the Industry recognizes that the existing registry
                                   has significant shortcomings with respect to both its
                                   maintainability and being able to quickly and cost
                                   effectively integrate new requirements.
                                   In 2002, NERC formed a Registry Task Force to address
                                   Industry concerns. That group recommended ]changes to
                                   the basic registry structure. Part of this Standards request
                                   would be to review that document and incorporate all
                                   pertinent functions called out by the Registry Task Force
                                   as part of this larger standards effort.


5. Description of Any Tangible or Intangible Benefits to the Use of the Proposed Standard or
   Enhancement:
                                     The Industry will benefit from a robust and reliable
                                     central source for information required to implement and
                                     enhance OASIS 1A, Electronic Tagging, Entity registration
                                     supporting the Functional Model, and also from a solid
                                     foundation to build on to meet OASIS II requirements.

6. Estimate of Incremental Specific Costs to Implement Proposed Standard or Enhancement:
                                    To be determined.


7. Description of Any Specific Legal or Other Considerations:
                                     This standards development process will require the close
                                     coordination between the NAESB WEQ and appropriate
                                     NERC Committees, Subcommittees, and Task Forces.
                                         R04037
        Request for Initiation of a NAESB Standard for Electronic Business Transactions or
       Request for Enhancement of a NAESB Standard for Electronic Business Transactions
                                                                                   Page 4



8. If This Proposed Standard or Enhancement Is Not Tested Yet, List Trading Partners Willing
    to Test Standard or Enhancement (Corporations and contacts):
                                    To be Determined.



9. If This Proposed Standard or Enhancement Is In Use, Who are the Trading Partners :
                                    Not Applicable.


10. Attachments (such as : further detailed proposals, transaction data descriptions,
     information flows, implementation guides, business process descriptions, examples of
     ASC ANSI X12 mapped transactions):
                                    NERC Registry Task Force - Registry Technical
                                    Specification, Version 2.0.3, July 3, 2003, available from
                                    the NERC Registry Task Force.
PKI Implementation Plan for Electronic Tagging
Overview
NERC Electronic Tagging (E-Tagging) has been on-line since September, 1999. The functional
specifications for Electronic E-Tagging may be downloaded from the NERC website.
The Electronic Tagging - Functional Specification Version 1.7.095 document provides a detailed
specification for the communication of tagging information among the various services. Strict
gGuidelines concerning the security architecture for E-Tagging are enforced, both directly and
indirectly, throughout the specification.
NERC, the DoE and NAESB have workedjoined together to promote an energy industry
standard public key infrastructure, create the e-MARC PKI1.             This infrastructure is
intendeddesigned to facilitate secure electronic communications between systems sharing
sensitive energy related data and users accessing these systems. The e-MARC PKI is based on
the X.509 Public Key Infrastructure Certificate Policy and Certification Practices Framework,
Request for Comment (RFC) 2527 of the Internet
Engineering Task Force (IETF).

E-Tagging is currently vulnerable from a cyber-security standpoint on several fronts. In the
interim period until an industry standard PKI implementation is achieved, E-Tagging can benefit
significantly from a phased implementation of X.509 certificate based data encryption (Phase 1)
and mutual authentication (Phase 2).
This implementation plan document has been created to accomplish the following goals.:
1. Implement data encryption for all data communicated between E-Tagging services as soon as
   possible, and.
2. Lay the foundation for use of an industry standard PKI implementation the e-MARC
   infrastructure in E-Tagging in the future.


Implementation of Data Encryption – Phase 1
The standard for data encryption for Internet-based communications is Secure Socket Layer
(SSL). SSL is a protocol that is universally accepted for use in web browsers and web servers.


SSL uses PKI by allowing clients to encrypt data sent to a web server with that server’s public
key. The server, and only the server, can decrypt the data ensuring data confidentiality between
the client and the server.


All data communicated between Electronic E-Tagging services should be considered sensitive
and must therefore be encrypted.
1
    Energy Market Access and Reliability Certificates Public Key Infrastructure
To achieve data encryption between services, all E-Tagging services must implement server-side
SSL for http HTTP communication. The certificate used must be using an X.509 version 3
formatted certificate issued by a trusted vendor2. This has the following implications:
•   This means that eEvery E-Tagging service that receives E-Tagging messages must require
    that all every E-Tagging messages be sent on an SSL-encrypted socket connection, and must
    use an X.509 server certificate issued by a trusted vendor2 to establish that connection.
•   No E-Tagging service can, at this time, require a client certificate from the sender of an
    E-Tag message. As the E-MARC or other industry implementation plan advances, client
    certificates will be required, but at this time they can not be required.
•   All E-Tagging messages must be sent using port 443, the standard SSL HTTP socket port,
    instead of port 80, which is the standard non-encrypted HTTP socket port.
•   Because client-side certificates are not being used in this implementation plan, and server-
    side certificates are being used only for confidentiality, but not for authentication, no changes
    to the registry are required by this plan.

Because SSL does not alter HTTPhttp, but simply provides a “socket” for encrypting http HTTP
traffic, and because most commercially available HTTP servers and development tools support
the use of SSL connections, the cost of implementation should be fairly low. If, however, an
Electronic Tagging service implementation does not use a web server that supports SSL, the
costs will be greater.


Laying the Foundation for e-MARC - Phase 2
If implemented properly, a PKI, such as e-MARC, ensures the following security services:
•   Confidentiality: The assurance to an entity that no one can read a particular piece of data
    except the receiver(s) explicitly intended.
•   Authentication: The assurance to one entity that another entity is who he/she/it claims to be.
•   Integrity: The assurance to an entity that data has not been altered (intentionally or
    unintentionally) from sender to recipient and from time of transmission to time of receipt.
•   Technical Non-Repudiation: A party cannot deny having engaged in the transaction or
    having sent the electronic message.


A PKI, such as e-MARC, makes use of X.509 digital certificates installed on the client end to
perform the services listed above. Each server has a public key and a private key (i.e. SSL)
AND each client has a public key and a private key. This allows data to be encrypted in both
directions ensuring confidentiality while receiving and sending data. The presence of a unique
digital certificate and private key for each client provides for authentication ensures identity of

Definitions and registration procedures for trusted pre-“e-MARC” SSL certificate vendors must be developed.
the client to the server and vice versa.. The use of a digital signature to electronically “sign” the
data ensures integrity. The fact that the digital signature uses the sender’s private key (which
only the sender possesses) ensures non-repudiation[PS1][PS2].


The e-MARC implementation, if widely accepted and implemented, can significantly aid in the
management of identities across various industry systems. By providing one common identity
for clients across the industry, clients will not have to work with so many varying security
implementations.


The implementation of server-side SSL on all Electronic Tagging services will lay the
foundation for e--MARC by ensuring that all services are already communicating using SSL and
X.509 server certificates. The next steps become much more difficult due to the factors
involved. The implementation of a PKI withe-MARC client certificates depends on many
factors, including:
1. The approval of the e-MARC or other industry standard proposal,
2.The implementation of the root CA,
3.2.The accreditation of approved (e-MARC) vendors,
4.3.The migration of clients to (e-MARC) certificates,
5.4.The re-design of systems to implement a new client security architecture, and
6.5.Registration of server and client certificates so that E-Tag services can verify the identity of
    the other services with which they are communicating.


Plan Recommendation – Phase 1
The steps needed to ensure the implementation of server-side SSL with X.509 certificates on all
Electronic E-Tagging services include, but are not limited toare as follows. This recommendation
applies to all Tag Authority, Tag Approval, and Tag Agent listener functions that are the target
of an E-Tagging protocol message (i.e., implement an SMXP Method).:
1. Applicable modifications toModify the functional specification document and get approval
   of those modifications.
2. Establishing a recommended timeline for the implementation of SSL for all service
   communications within Electronic E-Tagging.
3. Monitoring the status of SSL implementation.

Note that this recommendation does not apply to the GUI’s or user interfaces offered by vendors.
However, vendors are strongly encouraged to implement SSL on user interfaces that utilize
public networks if they have not done so already.

The recommended timeline is as follows:
JuneSep. 11, 2004 All services governed by the functional specification may offer clients the
                  ability to communicate sensitive datasend E-Tagging messages using http
                  HTTP over SSL (httpsHTTPS). A service must continue to offer interactions
                  as beforeusing HTTP until the specification can be modified. However, all
                  clients will be strongly encouraged to interact with these services using SSL.
                  Every E-Tagging service offering SSL service will register tagging URLs
                  using “https” instead of “http” as the protocol designator, and will then be
                  required to accept connections on both ports 80 and 443, using the same URI
                  on both ports. Connections on port 80 will be unencrypted, as today.
                  Connections on port 443 will be encrypted using SSL and server-side
                  certificates.


FallJan. 4, 20054 All services must support client communicationsE-Tagging messages must be
                  sent using http HTTP over SSL (httpsHTPS); unencrypted client connections
                  to E-Tagging services will no longer be supportedallowed. All modifications
                  to the E-Tagging Functional Specification required to support the clientserver-
                  side use of SSL and X.509 certificates for encryption of all communications
                  between tag E-Tagging services must be approved. A phased implementation
                  plan will be developed for the integration of client-side X.509 certificates and
                  mutual authentication for all communications governed by the E-Tag
                  Functional Specification.
Future            Phase 2 - All services must communicate using e-MARC server and client
                  certificates. A phasstaged implementation plan will be developed for the
                  integration of client-side X.509 certificates and mutual authentication for all
                  communications governed by the E-Tagging Functional Specification.
Item 5.        Current Standards
Background
Larry Goins will discuss the SARS developed for INT-003-0, “Interchange Transaction
Implementation” and INT-004-0, “Interchange Transaction Modifications.”

Action
The subcommittee will review the comments to the INT standards and discuss whether additional
SAR changes are needed to the SARs that have been drafted.

Attachments
•   SAR Form – INT-003-0

•   SAR Form – INT-004-0

•   INT comments document
                       When completed, email to: gerry.cauley@nerc.net




Standard Authorization Request Form
Title of Proposed Standard    Interchange Transaction Implementation
Request Date                  03/10/05




SAR Requestor Information                             SAR Type (Put an ‘x’ in front of one of
                                                      these selections)
Name           Alan Boesch                                 New Standard


Primary Contact Alan Boesch                                Revision to existing Standard

Telephone      402-845-5210                                Withdrawal of existing Standard
Fax            402-845-5205
E-mail         agboesc@nppd.com                            Urgent Action



Purpose/Industry Need (Provide one or two sentences)
Revise the standard to match the responsibilities as defined in the functional
model. Provide a measurement for this standard.




                                          SAR-1
   Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies by
double clicking the grey boxes.)
             Reliability      Ensures the reliability of the bulk transmission system within its Reliability
             Authority        Authority area. This is the highest reliability authority.


             Balancing        Integrates resource plans ahead of time, and maintains load-interchange-
             Authority        resource balance within its metered boundary and supports system
                              frequency in real time
             Interchange      Authorizes valid and balanced Interchange Schedules
             Authority
             Planning         Plans the bulk electric system
             Authority
             Resource         Develops a long-term (>1year) plan for the resource adequacy of specific
             Planner          loads within a Planning Authority area.
             Transmission     Develops a long-term (>1 year) plan for the reliability of transmission
             Planner          systems within its portion of the Planning Authority area.
             Transmission     Provides transmission services to qualified market participants under
             Service          applicable transmission service agreements
             Provider
             Transmission     Owns transmission facilities
             Owner
             Transmission     Operates and maintains the transmission facilities, and executes switching
             Operator         orders
             Distribution     Provides and operates the “wires” between the transmission system and
             Provider         the customer
             Generator        Owns and maintains generation unit(s)
             Owner
             Generator        Operates generation unit(s) and performs the functions of supplying energy
             Operator         and Interconnected Operations Services
             Purchasing-      The function of purchasing or selling energy, capacity and all necessary
             Selling Entity   Interconnected Operations Services as required
             Market           Integrates energy, capacity, balancing, and transmission resources to
             Operator         achieve an economic, reliability-constrained dispatch.
             Load-Serving     Secures energy and transmission (and related generation services) to
             Entity           serve the end user




                                              SAR-2
Reliability and Market Interface Principles
Applicable Reliability Principles (Check boxes for all that apply by double clicking the
grey boxes.)
       1. Interconnected bulk electric 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 electric 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 electric
          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 electric
          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 electric systems.
       6. Personnel responsible for planning and operating interconnected bulk electric systems
          shall be trained, qualified and have the responsibility and authority to implement actions.
       7. The security of the interconnected bulk electric 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? (Select ‘yes’ or ‘no’ from the drop-down box by double clicking the grey area.)
  1. The planning and operation of bulk electric systems shall recognize that reliability is an
     essential requirement of a robust North American economy. Yes
  2. An Organization Standard shall not give any market participant an unfair competitive
     advantage.Yes
  3. An Organization Standard shall neither mandate nor prohibit any specific market structure. Yes
  4. An Organization Standard shall not preclude market solutions to achieving compliance with that
     Standard. Yes
  5. An Organization 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




                                              SAR-3
Detailed Description (Provide enough detail so that an independent entity familiar with the
industry could draft, modify, or withdraw a Standard based on this description.)

The current standard assigns transmission reliability responsibilities to the
Balancing Authority. These responsibilities should be performed by entities
responsible for the reliability of the transmission system. Requirement 6 of
INT-003-0 should be assigned to the TOP.
INT-03-0 does not have any measurements. Add a measurement that reflects the intent of the standard:
“Balancing Authorities shall provide evidence that they implemented equal and opposite Interchange
Schedules with Adjacent Balancing Authorities.”




Related Standards
Standard No.       Explanation




Related SARs
SAR ID             Explanation




Regional Differences
Region             Explanation
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC



                                            SAR-4
SERC
SPP
WECC

Related NERC Operating Policies or Planning Standards
ID            Explanation




                                 SAR-5
                       When completed, email to: gerry.cauley@nerc.net




Standard Authorization Request Form
Title of Proposed Standard    Interchange Transaction Modifications
Request Date                  03/11/05




SAR Requestor Information                            SAR Type (Put an ‘x’ in front of one of
                                                     these selections)
Name           Alan Boesch                                New Standard


Primary Contact Alan Boesch                               Revision to existing Standard

Telephone      402-845-5210                               Withdrawal of existing Standard
Fax            402-845-5205
E-mail         agboesc@nppd.com                           Urgent Action



Purpose/Industry Need (Provide one or two sentences)
Revise the standard to assure that modifications to tags for congestion
management are submitted prior to being implemented and existing tags are
adjusted upon loss of load or generation.




                                         SAR-1
   Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies by
double clicking the grey boxes.)
             Reliability      Ensures the reliability of the bulk transmission system within its Reliability
             Authority        Authority area. This is the highest reliability authority.


             Balancing        Integrates resource plans ahead of time, and maintains load-interchange-
             Authority        resource balance within its metered boundary and supports system
                              frequency in real time
             Interchange      Authorizes valid and balanced Interchange Schedules
             Authority
             Planning         Plans the bulk electric system
             Authority
             Resource         Develops a long-term (>1year) plan for the resource adequacy of specific
             Planner          loads within a Planning Authority area.
             Transmission     Develops a long-term (>1 year) plan for the reliability of transmission
             Planner          systems within its portion of the Planning Authority area.
             Transmission     Provides transmission services to qualified market participants under
             Service          applicable transmission service agreements
             Provider
             Transmission     Owns transmission facilities
             Owner
             Transmission     Operates and maintains the transmission facilities, and executes switching
             Operator         orders
             Distribution     Provides and operates the “wires” between the transmission system and
             Provider         the customer
             Generator        Owns and maintains generation unit(s)
             Owner
             Generator        Operates generation unit(s) and performs the functions of supplying energy
             Operator         and Interconnected Operations Services
             Purchasing-      The function of purchasing or selling energy, capacity and all necessary
             Selling Entity   Interconnected Operations Services as required
             Market           Integrates energy, capacity, balancing, and transmission resources to
             Operator         achieve an economic, reliability-constrained dispatch.
             Load-Serving     Secures energy and transmission (and related generation services) to
             Entity           serve the end user




                                              SAR-2
Reliability and Market Interface Principles
Applicable Reliability Principles (Check boxes for all that apply by double clicking the
grey boxes.)
       1. Interconnected bulk electric 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 electric 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 electric
          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 electric
          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 electric systems.
       6. Personnel responsible for planning and operating interconnected bulk electric systems
          shall be trained, qualified and have the responsibility and authority to implement actions.
       7. The security of the interconnected bulk electric 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? (Select ‘yes’ or ‘no’ from the drop-down box by double clicking the grey area.)
  1. The planning and operation of bulk electric systems shall recognize that reliability is an
     essential requirement of a robust North American economy. Yes
  2. An Organization Standard shall not give any market participant an unfair competitive
     advantage.Yes
  3. An Organization Standard shall neither mandate nor prohibit any specific market structure. Yes
  4. An Organization Standard shall not preclude market solutions to achieving compliance with that
     Standard. Yes
  5. An Organization 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




                                              SAR-3
Detailed Description (Provide enough detail so that an independent entity familiar with the
industry could draft, modify, or withdraw a Standard based on this description.)

Requirement R1 of standard INT-004-0 incorrectly allows interchange
transactions that are in progress or scheduled to start to be modified within
60 minutes for congestion management, loss of generation or loss of load.

As originally stated in policy for congestion management transactions will be
modified by the load Balancing Authority by curtailing the transaction. The 60
minute criterion is not applicable to congestion management.

 For loss of generation or loss of load, the schedule modification may be
required. If the generator or LSE does not take action the transactions can
be modified by the generation (loss of generation) and load (loss of load)
Balancing Authority via a tag curtailment request. The 60 minute criterion is
not applicable to these situations.


The requirement for submittal of tags for transactions that are initiated to mitigate SOLs or IROLs should
be moved to INT-001-0 (this is not a modification but a new transaction). Tags to accommodate
implementation of tags for emergency transactions to mitigate SOLs and IROLs must be tagged within 60
minutes.




Related Standards
Standard No.       Explanation
INT-001-1          See detailed description.




Related SARs
SAR ID             Explanation




                                             SAR-4
Regional Differences
Region        Explanation
ECAR
ERCOT
FRCC
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WECC

Related NERC Operating Policies or Planning Standards
ID            Explanation




                                 SAR-5
INT-001-0   The Purpose implies that the             Modify the purpose
            Reliability Coordinator assesses the     statement to clarify the roll
            tag prior to implementation. The         of the Reliability
            original language from the standard      Coordinator.
            included curtailments, which is an
            action that the RC is involved in.       This will resolved with the
                                                     clarification of the FM RC-
                                                     RA-TOP issue.
            Requirement 2.1, tagging for joint       Assign the responsibility for
            owned units, is not the responsibility   tagging joint owned units to
            of the Sink BA.                          the entity that is utilizing and
                                                     determining the amount of
                                                     MWs.
                                                     Add an interpretation to the
                                                     standard to clarify that the
                                                     sink BA is not responsible
                                                     for submitting the tag.
            Requirement 2.2- The language for        Change the language for
            tagging emergencies has changed          requirement 2.2.
            from “exempt from tagging for 60         Fix now “exempt from
            minutes” to “tagged within 60            tagging for 60 minutes”
            minutes”. As I interpret the original
            language the tag does not have to be     “To replace unexpected
            generated for the first 60 minutes.      generation loss, such as
            Anything that extends beyond that        through prearranged reserve
            period would be tagged.                  sharing agreements or other
                                                     arrangements. and all
                                                     emergency Transactions to
                                                     mitigate System
                                                     Operating Limit (SOL) or
                                                     Interconnection Reliability
                                                     Operating Limit (IROL)
                                                     violations.
                                                      “Such interchange shall be
                                                     tagged within is exempt from
                                                     tagging for 60 minutes from
                                                     the time at which the
                                                     Interchange Transaction
                                                     begins.”

                                                     Write an opinion letter on this
                                                     issue to send to the industry.

            None of the requirements applicable to Add measurements for PSEs
            the PSE are measured.                  or remove PSEs from the
                                                   standard.
                                                   Submit a SAR to add a
                                                   measurement if needed
INT-002-0   Requirement 1.5 is not a requirement    Remove requirement 1.5
            it is a statement.                      from the standard.
                                                    Wait until we get the
                                                    clarification of the FM RC-
                                                    RA-TOP issue.
            Requirement 2 remove                    Reasonableness is something
            “reasonableness of the Interchange      the GPE and LSE would
            Transaction tag”.                       review and is not the
                                                    responsibility of the
                                                    transmission service
                                                    provider.
                                                    Submit a SAR if we have
                                                    other issues with this
                                                    standard
            Capitalize “adjacent” in 3.4            Submit a SAR if we have
                                                    other issues with this
                                                    standard
            Requirement 5 says transmission         Transmission Operators
            operators will receive the tag status   (used to be Control Areas)
            through the Security Reliability        do not receive information
            Analysis Service.                       via Reliability Analysis
                                                    Service. All TOPs should
                                                    get the tag directly
                                                    Later Fix by TISWG/ Wait
                                                    until we get the clarification
                                                    of the FM RC-RA-TOP
                                                    issue.
            Requirement 4                           Develop an interpretation
                                                    that addresses passive
                                                    approval.
INT-003-0   Move requirement 2 to be requirement    Rearrange requirements to
            1.                                      follow a logical sequence
                                                    currently defined in section
                                                    B of Policy 3.
                                                    Fix if we are submitting a
                                                    SAR for something more
                                                    important
            Requirement 5 should be assigned to     BAs are not aware of
            TOPs                                    transmission operating
                                                    criteria this is something the
                                                    TOP should do or remove or
                                                    clarify the requirement.
                                                    Wait until we get the
                                                    clarification of the FM RC-
                                                    RA-TOP issue.
            There are no measurements for this      Develop measures to reflect
               standard.                                the requirements or move the
                                                        requirements to a reference
                                                        document.
                                                        Submit a SAR to add a
                                                        measurement if needed
INT-004-0      Requirement 1- If the TOP can modify Copy affected TOPs on tags
               a tag then he will have to get the tags. Later Fix by TISWG/ Wait
                                                        until we get the clarification
                                                        of the FM RC-RA-TOP
                                                        issue.
               Measure 1- This measure is assigned      Assign the measure to the
               to the BA the requirement is assigned PSE or delete the
               to the PSE.                              requirement.

                                                        “The Sink Balancing
                                                        Authority Purchasing-Selling
                                                        Entity shall provide evidence
                                                        that a revised tag was
                                                        provided when the deviation
                                                        exceeded the criteria in
                                                        Requirement R5.”

                                                        Fix with SAR.

               Compliance 1. The burden of proof        Assign the burden of proof to
               should be assigned to the entity         the PSE.
               responsible for the requirement.
                                                        “Periodic tag audit as
                                                        prescribed by NERC. For the
                                                        requested time period, the
                                                        Sink Balancing Authority
                                                        Purchasing-Selling Entity
                                                        shall provide the instances
                                                        when dynamic schedule
                                                        deviation exceeded the
                                                        criteria in Requirement 5 and
                                                        shall demonstrate that a
                                                        revised tag was submitted.”
                                                        Fix with SAR
               With the exception of requirement 5      Develop measures to reflect
               there are not any measures for the       the requirements or move the
               requirements.                            requirements to a reference
                                                        document.
                                                        Submit a SAR to add a
                                                        measurement if needed

A group consisting of Fred Kunkel, Ron Donahey, Larry Goins and myself will develop
SARS. I am the chair of the group.
Item 6.        MISO Operations
Background
Doug Hils will provide a brief overview of MISO operations, and discuss real-time and day-ahead
operations since MISO’s market startup on April 1.



Attachment
None
Item 7.         Black Oak Energy Interpretation Request
Background
Doug Hils will discuss the Black Oak Energy request for an interpretation regarding curtailments
between the New York ISO and Black Oak. Serge Picard, managing director of Black Oak, will
be available to answer questions by teleconference.



Actions
The subcommittee should provide guidance on the Black Oak Energy interpretation request, and
decide if NERC needs to develop an interpretation.



Attachment
Letter – NYISO operations as a NERC control area, dated April 28, 2005
28/4/2005


Bill D. Blevins
Manager of Interchange
North American Electric Reliability Council
Princeton, NJ




Subject: NYISO operations as a NERC control area



Mr. Blevins,

The purpose of this letter is to request clarification of proper implementation of NERC standards by NYISO control area. Black Oak
Energy LLC, has been involved in many transactions where NYISO systematically curtails physical flow in or out of their control area,
with baseless justifications that do not seem to follow proper NERC procedure. Recent occurrences of unjustifiable curtailments for
control area interchange by NYISO have prompted our calls to NERC to try to bring light to this issue.

1) Day Ahead Schedules.

NYISO uses a quasi active approval process for tags. For example, a tag which doesn’t match with their bidding and scheduling MIS
(market interface system) system schedule will go into study mode, then into passive approval mode after 2 hours. These tags are later
curtailed by NYISO not due to a constraint, but do to a mismatched schedule in their MIS system when they compare it to the tag. A
further explanation of this example is; a mistyped PSE in the MIS bidding and scheduling system caused a day ahead tag to go through
the study mode, then be passively approved and implemented as a day ahead tag. Finally 20 minutes before flow, NYISO curtailed the
transaction due to a typo in the internal MIS system.

The market participant has to input the tag details in the MIS system for NYISO. NYISO tries to match up the tag information with
their internal bidding and offering system. NYISO effectively requires perfect NERC TAG information close to 36 hours before start of
flow for a day ahead schedule because they do not allow for any modifications to the frozen MIS fields.

The only way to notice a mismatch between the day ahead tag and the NYISO’s MIS system is to open the details of the tag and look
for NYISO’s message in the tag approve field. Apparently the market participant PSE should go in the tag approval process (click on
pending) and see the manner in which NYISO acted as a control area and verify what type of approval process the tag went through to
get implemented. To our dismay (as well as other companies and neighboring control areas) NYISO let’s the tag go IMPLEMENTED
and 20 minutes before flow they curtail the flow.



103 Carnegie Center                                                                                      Ph: (609) 275-7260
Suite 115                                                                                                Fax: (609) 275-7263
Princeton, NJ 085400
www.blackoakenergy.com
There is no notification to the market participant by NYISO, written or oral, to try to correct the situation before curtailment. There is
also no time to resubmit a new tag when the curtailment decision is made.



BLACK OAK ENERGY LLC, is requesting an interpretation of policy on conduct by NYISO. Is NYISO using proper NERC
procedure as a control area? Is NYISO using the curtail feature correctly for approved inter control area flow ? If not, might
NYISO be causing reliability issues by acting this way?



2) Real Time Schedules

The situation is similar with real time schedules where NYISO requires perfect NERC tag information on first submittal 1 hour 15
minutes before flow without possibility of retagging for errors or change in Tag. The problem began sometime last summer when
NYISO tried to implement E-tagging. While doing so they “froze” the field in their Market Interface System ,MIS, where we submit
bids and offers with associated prices for physical imports or exports. NERC standards allow for retagging up to 20 minutes before the
start of flow. You cannot retag any tag in the next hour market for NYISO because the MIS fields are frozen an hour and fifteen minute
before the start of the schedule. Any schedule retagged will automatically be denied. In addition NYISO will not approve any PSE
adjusted tags inside that 1 hour and fifteen minute window.



BLACK OAK ENERGY LLC, is requesting an interpretation of policy on conduct by NYISO. Is NYISO using E-tagging
properly by not allowing for retagging up to 20 minutes before flow? Is NYISO permitted to automatically deny all tag
adjustments inside the 1 hour and fifteen minute window?




Serge Picard

Managing Director
Black Oak Energy
Item 8.        Reference Document Updates
Background
Melinda Montgomery will report on the progress of updating the Dynamic Transfer and
Interchange Reference Documents.

Doug Hils will report on the status of revisions to the MISO Control Area Working Group’s
(CAWG) waiver documents.

Actions
The subcommittee should review and edit the documents at the meeting, if needed, and decide
whether they are ready for posting.



Attachments
•   Dynamic Transfer Reference Document, Version 1.1

•   Interchange Reference Document, Version 4
                                                       Approved by the Operating Committee on
                                                       March 25, 2004.




 NORTH AMERICAN ELECTRIC RELIABILITY COUNCIL
     Princeton Forrestal Village, 116-390 Village Boulevard, Princeton, New Jersey 08540-5731




Dynamic Transfer Reference Document
                                       Version 1.1



                           November 29, 2004




                             A New Jersey Nonprofit Corporation

             Phone 609-452-8060        Fax 609-452-9550       URL www.nerc.com
Dynamic Transfer Reference Document


Table of Contents

Overview ......................................................................................................................................3

A.         Dynamic Schedule ..........................................................................................................6

           1.        Telemetry............................................................................................................................ 6

           2.        Transmission Service ....................................................................................................... 6

           3.        System Modeling ............................................................................................................... 6

           4.        Dynamic Schedule Coordination and Scheduling ......................................................... 7

           5.        Trouble Response ............................................................................................................. 7

           6.        Compliance with NERC Operating Standard .................................................................. 8


B.         Pseudo-Tie.......................................................................................................................9

           1.        Telemetry............................................................................................................................ 9

           2.        Transmission Service ....................................................................................................... 9

           3.        System Modeling ............................................................................................................... 9

           4.        Pseudo-Ties Coordination and Scheduling.................................................................. 10

           5.        Trouble Response ........................................................................................................... 10

           6.        Compliance with NERC Operating Standard ................................................................ 10


C.         System Modeling...........................................................................................................11

Appendix A — Proposed Definitions ......................................................................................13

Appendix B — Dynamic Transfer Requirements ...................................................................14

Appendix C — ACE Equation Implications of Dynamic Transfers.......................................17

Appendix D — Supplemental Regulation Service as a Dynamic Schedule.........................24




Version 1.1                                                      DTR−2                        Approved by Operating Committee:
                                                                                                                 March 25, 2004
                                                                                        Revised by Dynamic Transfer Task Force:
                                                                                                             November 29, 2004
Dynamic Transfer Reference Document




Overview
The purpose of this document is to provide guidance to the industry on the responsibilities, requirements,
and expectations placed upon parties involved in establishing a dynamic transfer. The reference
document is needed to bring standardization to the industry regarding implementation and operation of
dynamic transfers. The paper may be used to help determine how to design and implement dynamic
transfer control schemes to meet the implementation requirements for a specific set of operating
conditions, system requirements, balancing authority-related jurisdictional responsibilities, and
commercial arrangements (to include providing balancing authority services).

There is not a consistent set of guidelines for dynamic transfers, and NERC policies[BDB1] do not address
the implementation of dynamic transfers. Accordingly, various interpretations exist within the industry
on how to implement, operate, and account for dynamic transfers. Common definitions and a minimum
set of requirements should ensure the future reliable implementation of dynamic transfers.

The intent of this reference document is to provide guidelines for future implementations of dynamic
transfers. To the extent that dynamic transfers are compliant with all applicable NERC policies[BDB2], it
is neither within the scope of this reference document nor the intention of the Dynamic Transfer Task
Force to require any organization to have to modify any existing dynamic transfers, particularly those
used to implement grandfathered contractual arrangements.

Terms

DYNAMIC TRANSFER — A term that refers to methods by which the control response to loads or
     generation is assigned, on a real-time basis, from the balancing authority to which such loads or
     generation are electrically interconnected (native balancing authority) to another balancing
     authority (attaining balancing authority) on a real-time basis. Depending on desired
     implementation of system control as well as various contractual, jurisdictional and regulatory
     responsibilities between the native and attaining balancing authority(s) , one of the two methods
     of the dynamic transfer may be employed: 1) dynamic schedule, or 2) pseudo-tie:

DYNAMIC SCHEDULE — A telemetered reading, or value that is updated in real-time and used as a
     schedule in the AGC/ACE equation of the affected balancing authority(s) and the integration of
     which is treated as a schedule for interchange accounting purposes.

PSEUDO-TIE — A telemetered reading, or value that is updated in real time, that represents generation or
      load assigned dynamically between balancing authority(s) and used as a tie line flow in the
      affected balancing authority’s AGC/ACE equation, but for which no physical balancing authority
      tie actually exists. To the extent that no associated energy metering equipment exists, the
      integration of the telemetered real time signal is used as a metered MWh value for interchange
      accounting purposes.

INTEGRATION, in the terms above means the value could be mathematically calculated or determined
mechanically with a metering device.

The key difference between pseudo-ties and dynamic schedules from the system control point of view is
in how the transfer is implemented in each balancing authority’s ACE equations and in the associated

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energy accounting processes. By definition, pseudo-ties are accounted for by all parties as actual
interchange and dynamic schedules are accounted for as scheduled interchange.

NOTE: In this document, the use of the term balancing authority is intended to be consistent with that
defined in the NERC operating policies[BDB3].

The particular dynamic transfer method to be utilized for a specific operating arrangement may be
dependent upon on some or all of the following:

    • Desired service(s) to be provided

    • The capability to capture the dynamic transfer in system models

    • Responsibility for forecasting load

    • Responsibility for providing unit commitment and maintenance information

    • EMS capability

Each balancing authority is obligated to fulfill its commitment to the Interconnection and not burden other
balancing authority(s) in the Interconnection. The use of a dynamic transfer does not in any way
diminish this responsibility.

    •   Before implementing the dynamic transfer, all parties to the dynamic transfer must agree on all
        implementation issues.

    •   Any errors resulting from an improperly implemented or operated dynamic transfer (including
        inadvertent accumulations) must be resolved between the involved parties and must not be in any
        way passed to the Interconnection.

    •   Dynamic transfers must NOT include any control offsets that are not explicitly compliant with the
        requirements set forth in NERC policies[BDB4] (e.g., unilateral inadvertent payback, Western
        Interconnection automatic time error control, etc.).

    •   Each balancing authority must ensure that the dynamic transfer of load or generation is
        coordinated with the Reliability Coordinator(s) that have responsibility over the native, attaining,
        and intermediary balancing authority(s) so that the particular method of dynamic transfer can be
        considered in the system modeling of the generation or load affected, and necessary data
        provision requirements are met. [See also, Appendix[BDB5] 4B, “Electric System Security Data.”]

    •   Applicable tariff requirements of all involved, or affected, transmission providers and balancing
        authority(s) must be met (this includes proper handling and accounting for energy losses).

    •   If the dynamic transfer includes a pre-arranged calculated assistance (or distribution of
        responsibility) between the native balancing authority and the attaining balancing authority for
        recovery from the loss of generation, then both balancing authority(s) are responsible for
        ensuring that their respective DCS compliance reporting requirements are met in accordance with
        NERC Standard BAL-002-0 — Disturbance Control Performance .


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A.       Dynamic Schedule
A dynamic schedule is implemented as an interchange transaction that is modified in real-time to transfer
time-varying amounts of power between balancing authority(s) . A dynamic schedule typically does not
change a balancing authority’s jurisdiction; that is, the native balancing authority continues to exercise
operational jurisdiction over, and provides basic balancing authority services to, the dynamically
scheduled resources.

Dynamic schedules are typically utilized in, but not limited, to the following scenarios

     •   Transfer all, or a portion of, actual output of a specific generator(s) to another balancing authority
         in real-time,

     •   Enable resources in one balancing authority to provide the real-time power requirements for a
         load in another balancing authority, or

     •   Enable generators, loads, or both in one balancing authority to supply one or more Interconnected
         Operations Services to generators, loads, or both in another balancing authority, or

     •   Provide a mechanism for reserve sharing.

Dynamic schedules are to be accounted for as interchange schedules by the source, sink, and contract
intermediary balancing authority(s) (CIBA), both in their respective ACE equations, and throughout all
of their energy accounting processes. Requirement to incorporate into the CIBA’s ACE is subject to
regional procedures.

All dynamic schedules used to assign the control of generation, loads, or resources from one balancing
authority to another must meet the following requirements:

1.       Telemetry

                 Pursuant to NERC Standard BAL-002-0 — Disturbance Control Performance, R12.1,
                 appropriate telemetry must be in place and incorporated by all affected balancing
                 authority(s).

2.       Transmission Service

                 Prior to implementation of the dynamic transfer of load or generation, it is the obligation
                 of each involved balancing authority to ensure that the dynamic transfer is implemented
                 such that the tariff requirements of the applicable transmission provider(s) are met,
                 including applicable ancillary services and provision of losses.

                 If transmission service between the source and sink balancing authority(s) is curtailed
                 then the allowable range of the magnitude of the schedules between them, including
                 dynamic schedules, may have to be curtailed accordingly.

3.       System Modeling



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              Each balancing authority must ensure that the dynamic transfer of load or generation
              through a dynamic schedule is coordinated with the Reliability Coordinator(s) with
              responsibility over the native, attaining, and contract intermediary balancing authority(s)
              so that the dynamic schedule can be properly implemented in the system modeling of the
              affected generation or load, and necessary data provision requirements are met.
              Coordination must include tagging of the resultant scheduled interchange for use by other
              transmission providers and balancing authority(s) for system security analysis and
              calculation of ATC. [See also, Appendix[BDB6] 4B, “Electric System Security Data.”]

              When a dynamic schedule is used to serve load within another balancing authority, the
              balancing authority where the load is electrically connected (native balancing authority)
              must include that load in its balancing authority load forecast and any subsequent
              reporting as needed. This is necessary because the system models must adequately
              capture the projected demand on the system (load forecast), and the projected supply
              (provided by the electronic tagging system).

4.     Dynamic Schedule Coordination and Scheduling

              Implementation of a dynamic schedule must be through the use of an interchange
              transaction between balancing authority(s). As such, all dynamic schedules must be
              tagged and implemented in accordance with NERC Standard INT-001-0 — Interchange
              Transaction Tagging, R1.

              Energy exchanged between the source, sink, and intermediary balancing authority(s) as a
              dynamic schedule is the metered or calculated (obtained by the integration of the
              dynamic schedule signal over the operating hour) energy for the loads and/or resources
              for the hour. Agreements must be in place with the applicable transmission providers to
              address the physical or financial provision of transmission losses.

              The native balancing authority must ensure that agreements are in place defining the
              responsibility for providing applicable ancillary/interconnected operations services.

5.     Trouble Response

              The native balancing authority, attaining balancing authority, and intermediary balancing
              authority(s) shall agree before implementation of the dynamic schedule on a plan for
              how the balancing authority(s) will operate during a loss of the dynamic schedule
              telemetry signal such that all involved balancing authority(s) are using the same value.
              The balancing authority(s) may agree to hold the last known good value, use an average
              load profile value, or have one party provide the other with a manual override value at
              some acceptable frequency of update.

              The native balancing authority, attaining balancing authority and intermediary balancing
              authority(s) shall agree before implementation of the dynamic schedule upon a plan for
              how the load will be served during abnormal system conditions including periods of time
              when the interconnection between them is unavailable. The native balancing authority,
              attaining balancing authority and intermediary balancing authority(s) shall also agree
              before implementation of the dynamic schedule as to how the generation serving the
              dynamic schedule will respond during abnormal system conditions, including periods of
              time when the interconnection between them is unavailable.
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6.     Compliance with NERC Operating Standards

               The implementation of a dynamic transfer may confer upon the attaining balancing
               authority additional responsibilities for compliance with NERC operating standards for
               the load or generation that has been transferred.

[See the Net Scheduled Interchange section of Appendix[BDB7] C, “ACE Equation Implications of
Dynamic Transfers.”]




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B.        Pseudo-Tie
Pseudo-ties are often employed to assign generators, loads, or both from the balancing authority to which
they are physically connected into a balancing authority that has effective operational control of them.
Thus, pseudo-ties provide for change of balancing authority jurisdiction from the native to the attaining
balancing authority and at the same time make the attaining balancing authority provider of balancing
authority services. This methodology is also referred to as “AGC Interchange” or “Non-Contiguous Pool
Tie.” In practice, pseudo-ties may be implemented based upon metered or calculated values. All
balancing authority(s) involved account for the power exchange and associated transmission losses as
actual interchange between the balancing authority(s), both in their ACE equations and throughout all of
their energy accounting processes.

All pseudo-ties used to assign generation, loads, or resources from the native balancing authority to the
attaining balancing authority must meet the following requirements:

1.        Telemetry

Pursuant to NERC Standard BAL-005-0 — Automatic Generation Control R12, R12.1 appropriate
telemetry must be in place and incorporated by all affected balancing authority(s).
2.      Transmission Service

          2.1.    Prior to implementation of the dynamic transfer of load or generation, each involved
                  balancing authority shall ensure that the dynamic transfer is implemented such that the
                  tariff requirements of the applicable transmission provider(s), including applicable
                  ancillary services and provision of losses, are met.

          2.2.    If transmission service between the native and attaining balancing authority(s) is
                  curtailed, then the allowable range of the magnitude of the pseudo-ties between them
                  must be limited accordingly to these constraints.

3.        System Modeling

          3.1.    The assignment of load or generation into the control response of another balancing
                  authority must be appropriately captured in the IDC and security analysis system models
                  of other transmission providers, balancing authority(s), and Reliability Coordinators. It is
                  the obligation of each balancing authority to ensure that the dynamic transfer of load or
                  generation is coordinated with the Reliability Coordinator(s) that have responsibility over
                  the native, attaining, and contract intermediary balancing authority(s) so that the method
                  of dynamic transfer can be properly implemented in the system modeling of the
                  generation or load affected, and necessary data provision requirements are met.1 [See
                  also Appendix[BDB8] 4B, “Electric System Security Data.”]

          3.2.    The attaining balancing authority dynamically transferring load into its effective
                  boundaries through a pseudo-tie shall ensure that load forecasts and subsequent balancing
                  authority reporting reflect the load incorporated within its balancing authority boundaries.


1
    References to the IDC may not apply to ERCOT or WECC.

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        3.3.    If the reliability impact of the pseudo-tie cannot be accurately captured in the IDC and
                the security analysis system models of other transmission providers, balancing
                authority(s), and Reliability Coordinators, the parties must implement the dynamic
                transfer either through use of a dynamic schedule, or through a combined implementation
                of pseudo-tie and dynamic schedule where the load or generation within the native
                balancing authority is separately modeled in the IDC. (See footnote 2.)

4.      Pseudo-Ties Coordination and Scheduling

Subsequent to moving load or resources into an attaining balancing authority through pseudo-ties, all
interchange transactions or other energy transfers to the loads or from the resources must be coordinated
through the operator of the attaining balancing authority as per the requirements of Standard INT-003-0
– Interchange Transaction Implementation R5 and R6.
        4.1.    The attaining balancing authority assumes responsibility for balancing authority services
                required by the assigned loads and/or resources. The attaining balancing authority
                assumes all regulation, contingency reserves, and other balancing authority
                responsibilities for the loads and/or resources in question.

        4.2.    Energy exchanged between the native and attaining balancing authority(s) by the pseudo-
                tie method is accounted for by the associated revenue meter reading for the operating
                hour (if such meter exists at the dynamically assigned resource or load) or energy
                calculated by integrating the associated telemetered real-time signal over the operating
                hour. Agreements must be in place with the applicable transmission providers to address
                the physical or financial provision of transmission losses.

5.      Trouble Response

        5.1.    The native balancing authority, attaining balancing authority and intermediary balancing
                authority(s) shall agree before implementation of the pseudo-tie on a plan for how the
                balancing authority(s) will operate during a loss of the pseudo-tie telemetry signal such
                that all involved balancing authority(s) are using the same value. The balancing
                authority(s) may agree to hold the last known good value, use an average load profile
                value, or have one party provide the other with a manual override value at some
                acceptable frequency of update.

        5.2.    The native balancing authority, attaining balancing authority, and intermediary balancing
                authority(s) should agree before implementation of the pseudo-tie upon a plan for how
                the load will be served during abnormal system conditions including periods of time
                when the interconnection between them is lost. The native balancing authority, attaining
                balancing authority, and intermediary balancing authority(s) shall also agree before
                implementation of the pseudo-tie how the entities will respond during abnormal system
                conditions, including periods of time when the connection between them is unavailable.

6.      Compliance with NERC Operating Standards

        6.1.    The implementation of a pseudo-tie may confer upon the attaining balancing authority
                additional responsibilities for compliance with NERC operating standard for the load or
                generation that has been transferred.


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[See the Net Actual Interchange section of Appendix[BDB9] C, “ACE Equation Implications of Dynamic
Transfers.”]

C.       System Modeling
The assignment of load or generation into the control response of another balancing authority must be
appropriately captured in the IDC and security analysis system models of other transmission providers,
balancing authority(s), and Reliability Coordinators. It is the obligation of each balancing authority to
ensure that the dynamic transfer of load or generation is coordinated with the Reliability Coordinator(s)
that have responsibility over the native, attaining, and contract intermediary balancing authority(s) so that
the method of dynamic transfer can be considered in the system modeling of the generation or load
affected, and necessary data provision requirements are met. [See also Appendix[BDB10] 4B, “Electric
System Security Data.”]

     •   It is the responsibility of the attaining balancing authority dynamically transferring load into its
         effective boundaries through Pseudo-Ties to ensure that load forecasts and subsequent balancing
         authority reporting reflect the load incorporated within its balancing authority boundaries.

     •   If the reliability impact of the Pseudo-Tie cannot be accurately captured in the IDC and the
         security analysis system models of other Transmission Providers, balancing authority(s), and
         Reliability Coordinators, the parties must implement the dynamic transfer either through use of a
         Dynamic Schedule, or through a combined implementation of a Pseudo-Tie and Dynamic
         Schedule where the load or generation within the native balancing authority is separately modeled
         in the IDC.




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                     Assignment of Balancing authority Obligations
      Balancing
     Authority’s                  Pseudo tie                                  Dynamic schedule
Obligation/modeling
Gen planning and     Attaining balancing authority                Typically, native balancing authority but
reporting and outage                                              may be re-assigned (wholly or a portion) to
coordination                                                      the attaining balancing authority

CPS and DCS recovery      Attaining balancing authority           Attaining and/or native balancing authority
/reporting and RMS                                                (depending on agreements)

Balancing authority       Attaining balancing authority           Native BA
jurisdiction

Balancing authority       Attaining balancing authority           Native BA
services

FERC Schedules 3–6
and other ancillary
services as required

Ancillary services        Attaining/native balancing authority    Attaining/Native BA (as agreed)
associated with           (as agreed)
transmission

FERC Schedules 1–2
and other ancillary
services as required

ACE frequency bias        The native and attaining balancing      The attaining balancing authority should
calc/setting              authority(s) shall adjust the control   include the load from its dynamic schedule
                          logic that determines their frequency   as a part of its forecast load to set
                          bias setting to account for the         frequency bias requirement. The native
                          frequency bias characteristics of the   balancing authority should change its load
                          loads and/or resources being assigned   used to set frequency bias setting by the
                          between balancing authority(s) by the   same amount in the opposite direction.
                          pseudo-tie

Load forecasting and      Attaining balancing authority           Native balancing authority
reporting




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Appendix A — Proposed Definitions


ATTAINING BALANCING AUTHORITY — A balancing authority bringing generation or load into its
      effective control boundaries through dynamic transfer from the Native Balancing authority.

DYNAMIC SCHEDULE — A telemetered reading, or value that is updated in real-time and used as a
     schedule in the AGC/ACE equation of the affected balancing authority(s) and the integration of
     which is treated as a schedule for interchange accounting purposes.

DYNAMIC TRANSFER — The provision of the real-time monitoring, telemetering, computer software,
     hardware, communications, engineering, energy accounting (including inadvertent interchange),
     and administration required to implement a dynamic schedule or pseudo-tie.

DYNAMIC TRANSFER SIGNAL — The electronic signal used to implement a pseudo-tie or dynamic
     schedule.

FREQUENCY RESPONSE — The provision of capacity from IOS resources that deploys automatically to
      stabilize frequency following a significant and sustained frequency deviation on the
      Interconnection. (IOS Reference Document)

INTEGRATION in the terms for dynamic schedule and pseudo-tie above means the value could be
      mathematically calculated or determined mechanically with a metering device.

INTERCONNECTED OPERATIONS SERVICE (IOS) — A service (exclusive of basic energy and
      transmission services) that is required to support the reliable operation of interconnected bulk
      electric systems. (IOS Reference Document)

NATIVE BALANCING AUTHORITY — A balancing authority from which a portion of its physically
      interconnected generation and/or load is assigned from its effective control boundaries
      through dynamic transfer to the attaining balancing authority.

PSEUDO-TIE — A telemetered reading, or value that is updated in real time, representative of generation
      or load assigned dynamically between balancing authority(s) and used as a tie line flow in the
      affected balancing authority’s AGC/ACE equation, but for which no physical balancing authority
      tie actually exists. To the extent that no associated energy metering equipment exists, the
      integration of the telemetered real time signal is used as a metered MWh value for interchange
      accounting purposes.

REGULATION — The provision of generation and load response capability, including capacity, energy,
     and maneuverability that respond to automatic controls issued by the Balancing Authority. (IOS
     Reference Document)




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Appendix B — Dynamic Transfer Requirements


To implement a dynamic transfer the following entities must:

Requirements — Operating Authority(s)

 1.     Dynamic Transfer Signal

        PSEUDO-TIE — The native, attaining, and contract intermediary balancing authority(s) shall each
              receive the dynamic transfer signals and incorporate it into their AGC systems on the
              NET actual interchange side of their ACE equation, in the same way as is done with
              metered interchange.

        DYNAMIC SCHEDULE — The source, sink, and contract intermediary balancing authority(s) shall
             each receive the dynamic transfer signal and incorporate it into their AGC systems on the
             net scheduled interchange side of their ACE equation, in the same way as is done with
             schedules.

 2.     Performance Requirements

        Use of a pseudo-tie or dynamic schedule does not exempt a balancing authority from complying
        with the control performance and interchange scheduling requirements of Policies[BDB11] 1 and 3.

 3.     Coordination of ACE

        PSEUDO-TIE — The native, attaining, and contract intermediary balancing authority(s) involved
              in a pseudo-tie shall incorporate the common AGC interchange signal into the actual
              interchange portion of their AGC/ACE equations.

        DYNAMIC SCHEDULE — The source, sink, and contract intermediary balancing authority(s) shall
             incorporate dynamic schedule signals into the scheduled interchange portion of their
             AGC/ACE equations.

 4.     Frequency Bias Setting Adjustment

PSEUDO-TIE — The native and attaining balancing authority(s) shall adjust the control logic that
determines their frequency bias setting to account for the frequency bias characteristics of the loads
and/or resources being assigned between balancing authority(s) by the pseudo-tie. [Standard BAL-003-
0 — Frequency Response and Bias]
        DYNAMIC SCHEDULE — The attaining balancing authority should include the load from its
                dynamic schedule as a part of its forecast load to set frequency bias requirement. The
                native balancing authority should change its load used to set frequency bias setting by the
                same amount in the opposite direction.




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 5.    Scheduling of Transmission

       Transmission service must be procured per the tariff requirements of the applicable transmission
       provider(s).

       All transmission necessary to deliver the energy must be reserved and scheduled with the native,
       attaining, and contract intermediary balancing authority(s) according to the applicable
       requirements specified in Standard INT-003-0 – Interchange Transaction Implementation R6.1.

 6.    Coordination of Power Transfers

       The native, attaining, and contract intermediary balancing authority(s) shall agree upon the
       allowable characteristics of the power transfers and the method for calculation of the maximum
       magnitude of the dynamic transfer signal(s) as appropriate.

       Dynamic schedules are to be implemented in the ACE equation as scheduled interchange in the
       direction from the generation balancing authority to the load balancing authority. If the power
       flows associated with the dynamic schedule were expected to be bi-directional, two separate
       dynamic schedules would be required (each schedule to be implemented as unidirectional
       following the “gen-to-load” direction convention).

       The balancing authority shall ensure that the applicable limits applied to the particular method of
       the dynamic transfer meet the requirements of the transmission provider.

 7.    Metering and Communications

       The native, attaining, and contract intermediary balancing authority(s) shall agree upon the
       metering and telecommunications requirements for the pseudo-ties or dynamic schedule(s).
       Balancing Authority(s) shall comply with these requirements in the implementation of the
       dynamic transfer(s).

 8.    Calculation of Actual Energy Transfer

       The native, attaining, and contract intermediary balancing authority(s) shall agree on the method
       to be used for calculating the total amount of energy transferred (including losses) through the
       dynamic transfer on an hourly basis. Balancing Authority(s) will check and agree on such hourly,
       calculated energy transfers and use these checked and agreed quantities in all of their energy
       accounting.

 9.    Loss of Dynamic Transfer Signal

       Prior to implementation of the dynamic transfer, the involved balancing authority(s) shall agree
       on actions and/or procedures to be implemented in an event of loss of the dynamic signal. Such
       agreed upon actions and/or procedures must be implemented any time the native, attaining, or
       contract intermediary balancing authority loses the dynamic transfer signal.

10.    Base Case Load Study Case

       The use of transmission service for a dynamic transfer shall be modeled in the base case power
       flow study cases. Such modeling must be done for the dynamic transfer at each end of its range,
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       and for as many other points within its range as required to ensure that the dynamic transfer will
       not cause reliability problems in real time.

Requirements — Operating Authority(s) and Load-Serving Entities

11.    Telemetry

       The entity requesting a pseudo-tie or dynamic schedule is responsible for ensuring that signal
       processing and communications equipment required in order to implement that specific type of
       dynamic transfer has been made available to each of the parties to the dynamic transfer. All
       dynamic transfer signals must be received and utilized by the native, attaining, and contract
       intermediary balancing authority(s). All equipment installed as part of the dynamic transfer
       should have appropriate associated alarms implemented such that the party using that equipment
       immediately knows any equipment failure.

12.    Supporting Ancillary Services

       The entity requesting a dynamic transfer shall schedule, in accordance with tariffs of the
       applicable transmission provider(s), ancillary services necessary to implement the dynamic
       transfer.

13.    Transmission Reservation

       Sufficient transmission service, with the tag indicating the appropriate priority, must be reserved
       throughout the contract path. (Note: Sufficient, in this context, means, “transmission whose
       availability is commensurate with the energy supplier’s commercial obligations to deliver energy
       to their customer.”)

14.    Transmission Scheduling

       Transmission service to enable the dynamic transfer must be reserved consistent with the tariff
       requirements of the applicable transmission provider(s) throughout the contract path

15.    Transaction Tagging

       The entity requesting a dynamic transfer through a dynamic schedule shall be responsible for
       submitting an interchange transaction tag for the schedule. [Standard INT-001-0 — Interchange
       Transaction Tagging, R1.]




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Appendix C — ACE Equation Implications of Dynamic
Transfers
ACE = {[Net Actual] – [Net Schedule]} − 10Fb (FA − FS) − IME                                                                                        (1)

         --------------------------------------------------------------------------------------------------------------------------------------------


ACE = {[NIA] − [NIS]} − 10Fb (FA − FS) − IME                                                                                                        (2)

         --------------------------------------------------------------------------------------------------------------------------------------------


ACE = {[(NIa) + (NIAPTGE − NIAPTGI − NIAPTLE + NIAPTLI)]

            − [(NIs) + (− NISDSGE + NISDSGI + NISDSLE − NISDSLI – NSRSE + NSRSI)] }

            − 10Fb (FA − FS) − IME                                                                                                                  (3)
where:

         Net Actual Interchange (NIA)
         Affected by pseudo-ties/AGC interchanges

                     NIA = (SUM of Tie Lines) + (SUM of Pseudo-Ties)

                     NIA = (NIa) + (NIAPTGE − NIAPTGI − NIAPTLE + NIAPTLI)

                     where:

                                  NIa            =     Net sum of tie line flows
                                  NIAPTGE =            sum of AGC interchange generation external to the attaining A
                                                       balancing authority.
                                  NIAPTGI =            sum of AGC interchange generation internal to the balancing
                                                       authority (native balancing authority).
                                  NIAPTLE =            sum of AGC interchange load external to the balancing authority
                                                       (attaining balancing authority).
                                  NIAPTLI =            sum of AGC interchange load internal to the balancing authority
                                                       (native balancing authority).
                     and where values for all generation and load terms are assumed to be positive quantities




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       Net Scheduled Interchange (NIS)
       Affected by dynamic schedules and supplemental regulation services.

                 NIS = (SUM of non-dynamically scheduled transactions) + (SUM of Dynamic Schedules)

                 NIS = (NIs) + (− NISDSGE + NISDSGI + NISDSLE − NISDSLI – NSRSE + NSRSI)

                 where :

                           NIs     =    Net sum of non-dynamically scheduled transactions
                           NISDSGE =    sum of dynamically scheduled generation external to the attaining
                                        balancing authority
                           NISDSGI =    sum of dynamically scheduled generation internal to the
                                        native balancing authority
                           NISDSLE =    sum of dynamically scheduled load external to the
                                        attaining balancing authority
                           NISDSLI =    sum of dynamically scheduled load internal to the
                                        native balancing authority
                           NISRSE   =   supplemental regulation service external to the balancing authority
                                        (balancing authority purchasing the supplemental regulation
                                        service). See Appendix[BDB12] D.
                           NISRSI   =   Supplemental regulation service internal to the BALANCING
                                        AUTHORITY (Balancing authority selling the supplemental
                                        regulation service). See Appendix[BDB13] D.

                   and where values for all generation and load terms are assumed to be positive
                   quantities

                   See also Operating Manual[BDB14], Appendix[BDB15] 1A, subsection D – “The Area
                   Control Error (ACE) Equation” for further discussions of the required ACE equation
                   modifications using dynamic schedules
       Terms Unaffected by Dynamic Transfers
              Fb = Balancing Authority Frequency Bias
              FA = Actual Frequency
              FS = Scheduled Frequency
              IME = Meter Error Correction

The following are the purposes for which dynamic transfers are typically implemented.

   •   Move a load out of a native balancing authority and into an attaining balancing authority.
   •   Move a generator out of a native balancing authority and into an attaining balancing authority.
   •   Serve load with energy that is sourced from a balancing authority other than that in which it
       resides.
   •   Schedule the output of a generator to balancing authority other than that in which it resides.
   •   Provide supplemental regulation services, as described in Appendix[BDB16] D.
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The following sections show which specific component should be used by each involved balancing
authority to reflect each type of dynamic transfer in its ACE equation.
Application of Pseudo-ties in ACE by Balancing Authority(s)


                     Balancin           Balancin               Balancin
                        g                  g                      g
                     Authority          Authority              Authority



       (A     B)      Balancing Authority(s) A and B are Adjacent Balancing Authority(s).
       (A     C B)    Balancing Authority C is an Intermediate Balancing Authority.
       (A     C)      Balancing Authority(s) A and C are Adjacent Balancing Authority(s).
       (A     B C)    Balancing Authority B is an Intermediate Balancing Authority.

                                             Table C-1
                                       Balancing             Balancing             Balancing
                                      Authority A           Authority B           Authority C
  P1   Generator
       From A to B         A B           NIAPTGI               NIAPTGE                  --
       Path A B
  P2   Generator           A C           NIAPTGI                  --                 NIAPTGE
       From A to B
       Path A C B          C B              --                 NIAPTGE               NIAPTGI

  P3   Generator
       From A to C         A C           NIAPTGI                  --                 NIAPTGE
       Path A C
  P4   Generator
       From A to C         A B           NIAPTGI               NIAPTGE                 --
       Path A B C          B C             --                  NIAPTGI               NIAPTGE

  P5   Load
       From A to B         A B           NIAPTLI               NIAPTLE                  --
       Path A B
  P6   Load
       From A to B         A C           NIAPTLI                 --                  NIAPTLE
       Path A C B          C B             --                  NIAPTLE               NIAPTLI

  P7   Load
       From A to C         A C           NIAPTLI                  --                 NIAPTLE
       Path A C




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  P8   Load
       From A to C    A B               --          NIAPTLE             NIAPTLE
       Path A B C     B C             NIAPTLI       NIAPTLI               --




Version 1.1                           DTR−20          Approved by Operating Committee:
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Dynamic Transfer Reference Document


Application of Dynamic Schedules in ACE by Balancing Authority(s)



                      Balancin           Balancin               Balancin
                         g                  g                      g
                      Authority          Authority              Authority



       (A     B)       Balancing Authority(s) A and B are Adjacent Balancing Authority(s).
       (A     C B)     Balancing Authority C is an Intermediary Balancing Authority.
       (A     C)       Balancing Authority(s) A and C are Adjacent Balancing Authority(s).
       (A     B C)     Balancing Authority B is an Intermediary Balancing Authority.

                                              Table C-2
                                        Balancing             Balancing             Balancing
                                       Authority A           Authority B           Authority C
  S1   Resource output
       From A to B          A B           NISPTGI               NISPTGE                  --
       Path A B
  S2   Resource output      A C           NISPTGI                  --                 NISPTGE
       From A to B
       Path A C B           C B              --                 NISPTGE               NISPTGI

  S3   Resource output
       From A to C          A C           NISPTGI                  --                 NISPTGE
       Path A C
  S4   Resource output
       From A to C          A B           NISPTGI               NISPTGE                  --
       Path A B C           B C             --                  NISPTGI               NISPTGE

  S5   Serve a Load
       In B from A          A B           NISPTLI               NISPTLE                  --
       Path A B
  S6   Serve a Load
       In B from A          A C           NISPTLI                 --                  NISPTLE
       Path A C B           C B             --                  NISPTLE               NISPTLI

  S7   Serve a Load
       In C from A          A C           NISPTLI                  --                 NISPTLE
       Path A C
  S8   Serve a Load
       In C from A          A B             --                  NIAPTLE               NIAPTLE
       Path A B C           B C           NIAPTLI               NIAPTLI


Version 1.1                                DTR−21                Approved by Operating Committee:
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Dynamic Transfer Reference Document




Numeric Examples



              BA A –           T     BA B –
                                     Loa
              1                        7
               Ge    Loa
                       5                       2
                                               Ge
  Assume: Net sum of tie flows = 0,
            Net sum of non-dynamically
  scheduled transactions = 0,




In these examples, balancing authority west will become the attaining balancing authority for load Y and
generator Z. Similarly, balancing authority east will become the attaining balancing authority for load X
and generator W.

Using Dynamic Schedules:

        Using Table C-2, rows S1 and S5, to obtain the correct net scheduled interchange terms for the
        dynamic schedules, the ACE equation for balancing authority west becomes:

        ACE Balancing Authority West = NIA – NIS = NIA – (NIs − NISDSGE + NISDSGI + NISDSLE − NISDSLI)
                           = NIA – (NIs − Gen Z + Gen W + Load Y − Load X)

        Substituting the values in the example as positive quantities, the equation becomes:

        ACE Balancing Authority West = 0 – ( 0 – 200 + 100 + 75 – 50)
                           = 0 – ( – 75) = 75

Using Pseudo-Ties:

        Using Table C-1, rows P1 and P5, to obtain the correct net actual interchange terms for the
        pseudo-ties, the ACE equation becomes:

        ACE Balancing Authority West = NIA – NIS = (NIa + Gen Z − Gen W − Load Y + Load X) – NIS

        Substituting the values in the example as positive quantities, the equation becomes:

Version 1.1                                     DTR−22                 Approved by Operating Committee:
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                                                                 Revised by Dynamic Transfer Task Force:
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Dynamic Transfer Reference Document


        ACE Balancing Authority West = (0 + 200 − 100 − 75 + 50) – 0
                            = 75


Using both Dynamic Schedules and Pseudo-ties

Assume that the generation will be modeled as dynamic schedules and the loads as pseudo-ties. Using
Table C-2, Row S1 and Table C-1, Row P5 to obtain the correct Net Scheduled Interchange and Net
Actual Interchange terms for the dynamic transfers, the ACE equation for balancing authority A becomes:

ACE Balancing Authority West = NIA – NIS = (NIa − Load Y + Load X) – (NIs − Gen Z + Gen W)

Substituting the values in the example as positive quantities, the equation becomes:

ACE Balancing Authority West = (0 − 75 + 50) – (0 – 200 + 100)
                        = (− 25) – (– 100)
                        = −25 + 100 = 75

Note: In all cases the ACE value is the same regardless of the dynamic transfer method(s) used.




Version 1.1                                     DTR−23                  Approved by Operating Committee:
                                                                                           March 25, 2004
                                                                  Revised by Dynamic Transfer Task Force:
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Dynamic Transfer Reference Document



Appendix D — Supplemental Regulation Service as a
Dynamic Schedule


Supplemental regulation service is when one balancing authority provides all or part of the regulation
requirements of another balancing authority. The balancing authority(s) implement a dynamic schedule
incorporating the calculated portion of the ACE signal that has been agreed upon between them. This is
accomplished by adding another component to the scheduled interchange component of the ACE equation
for both balancing authority(s). Care should be taken to maintain the proper sign convention to ensure
proper control, with the balancing authority purchasing regulation service subtracting the supplemental
regulation SERVICE from their ACE while the balancing authority providing the service adds it to theirs.

If the supplemental regulation service includes a calculated assistance between the native balancing
authority and the attaining balancing authority for recovery from the loss of generation, then both
balancing authority(s) are responsible for assuring that DCS compliance reporting requirements are met
in accordance with NERC Standard BAL-002-0 — Disturbance Control Performance.

Note that all requirements for dynamic scheduling must be observed while providing supplemental
regulation service. ACE equation modifications required for supplemental regulation service:

ACE Equation Modifications

        Typically:

        ACE = (NIA − NIS) − 10Fb (FA − FS) − IME

        where:

                 NIA = Net Actual Interchange

                 NIS = Net Scheduled Interchange

                 Fb = Balancing Authority Frequency Bias

                 FA = Actual Frequency

                 FS = Scheduled Frequency

                 IME = Meter Error Correction

        For a DYNAMIC SCHEDULE the NIA remains unchanged, but the NIS term becomes:

                 NIS = NIs − NISDSGE + NISDSGI + NISDGLE − NISDSLI

        where:

                 NIs = Net sum of non-dynamically scheduled transactions

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                NISDSGE = sum of dynamically scheduled generation external to the balancing authority
                    (attaining balancing authority).

                NISDSGI = sum of dynamically scheduled generation internal to the balancing authority
                    (native balancing authority).

                NISDSLI = sum of dynamically scheduled load internal to the balancing authority (native
                    balancing authority).

       For a dynamic schedule used to implement supplemental regulation service the NIA remains
       unchanged, but the NIS term becomes:

       NIS = NIs − NISDSGE + NISDSGI + NISDGLE − NISDSLI – NISRSE + NISRSI

       where:

                NIs = Net sum of non-dynamically scheduled transactions.

                NISDSGE = sum of dynamically scheduled generation external to the balancing authority
                    (attaining balancing authority).

                NISDSGI = sum of dynamically scheduled generation internal to the balancing authority
                    (native balancing authority).

                NISDSLE = sum of dynamically scheduled load external to the balancing authority
                    (attaining balancing authority).

                NISRSE = Supplemental regulation service external to the balancing authority (balancing
                    authority purchasing the supplemental regulation service).

                NISRSI = Supplemental regulation service internal to the balancing authority (balancing
                        authority selling the supplemental regulation service).

                and where supplemental regulation service for an overgeneration condition is assumed to
                       be negative and for undergeneration it is positive to achieve the desired effect via
                       NIS on ACE as described in the NERC Operating Manual[BDB17], Appendix 1A,
                       Subsection C, “The Area Control Error (ACE) Equation[BDB18].”




Version 1.1                                  DTR−25                Approved by Operating Committee:
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                                                             Revised by Dynamic Transfer Task Force:
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[BDB1]Should   this be changed to standards?

[BDB2]Does    this need to be changed to Standards?

[BDB3]Should   this be changed to standards?

[BDB4]Will   this be in the NERC standard or somewhere else?

[BDB5]Appendixes   have been removed need to determine which standard/business practice has
the correct reference.

[BDB6]Appendixes   have been removed need to determine which standard/business practice has
the correct reference.

[BDB7]Appendixes   have been removed need to determine which standard/business practice has
the correct reference.

[BDB8]Appendixes   have been removed need to determine which standard/business practice has
the correct reference.

[BDB9]Appendixes   have been removed need to determine which standard/business practice has
the correct reference.

[BDB10]Appendixes   have been removed need to determine which standard/business practice has
the correct reference.

[BDB11]What    standard does the reference need to be?

[BDB12]Appendixes   have been removed need to determine which standard/business practice has
the correct reference.

[BDB13]Appendixes   have been removed need to determine which standard/business practice has
the correct reference.

[BDB14]Will   it still be in the manual if so what standard?

[BDB15]Appendixes   have been removed need to determine which standard/business practice has
the correct reference.

[BDB16]Appendixes   have been removed need to determine which standard/business practice has
the correct reference.

[BDB17]Will   it still be in the manual if so what standard?

           not find this in the new manual. Looked in the BAL standards and they have
[BDB18]Could
dropped Appendix A material on Pseudo and Dynamic schedules.
Interchange Reference Document

Reference Document Subsections
A. The Relationship between Interchange Transactions and Interchange Schedules
B. Interchange Schedules within a Multi-Party Regional Agreement or Transmission Tariff
C. Implementing Interchange Schedules


A.     The Relationship between Interchange Transactions and
       Interchange Schedules
The NERC Standards INT-003-0, INT-004-0, and TOP 006-0 contain requirements for arranging and
implementing INTERCHANGE TRANSACTIONS that are essential to the reliable operation of the
Interconnected Systems. Standards TOP 005-0, TOP 003-0 and PRC 001-0 explains the procedures for
assessing and confirming INTERCHANGE TRANSACTIONS and implementing INTERCHANGE SCHEDULES.
The flowchart on the right explains the process by which INTERCHANGE TRANSACTIONS become
INTERCHANGE SCHEDULES. The Electronic Tagging (E-Tag) systems provide tools for the responsible
entities to perform many of these functions. . Refer to the “E-tag Reference Document” and the “ERCOT
Tagging Reference Document” for further details.
PURCHASING-SELLING ENTITIES “arrange” INTERCHANGE TRANSACTIONS – that is, they buy or sell
energy and capacity and record the transaction by forwarding the required data via an INTERCHANGE
TRANSACTION “tag” to the appropriate Reliability Entities.
BALANCING AUTHORITIES, RELIABILITY AUTHORITIES, AND TRANSMISSION OPERATORS assess and
“approve” or “deny” INTERCHANGE TRANSACTIONS based on the criteria from Standard TOP 006-0.
Transmission Operators assess the impact of providing the requested transmission service when the
service is approved. To implement the INTERCHANGE TRANSACTION, all affected BALANCING
AUTHORITIES incorporate the INTERCHANGE TRANSACTION into their INTERCHANGE SCHEDULES as
explained on the following pages.
In this example, there are three INTERCHANGE TRANSACTIONS, IT1, IT2, and IT3, that                   A
result in a number of INTERCHANGE SCHEDULES between BALANCING AUTHORITY(S) A,           SAB
B, C, and D. (Refer to Figure 1 on the right and table below. For simplicity, we are           IT1       IT2
assuming that physical losses are not required.)
                                                                                                     B
Interchange Transaction 1 (IT1)
BALANCING AUTHORITY A is the SOURCE BALANCING AUTHORITY for INTERCHANGE                 SBC
TRANSACTION 1 (IT1) and BALANCING AUTHORITY B is the SINK BALANCING                                      IT3

AUTHORITY. To make IT1 occur, BALANCING AUTHORITY A implements an
INTERCHANGE SCHEDULE with BALANCING AUTHORITY B (SAB-IT1). In this case, the                         C
SOURCE BALANCING AUTHORITY A is the SENDING BALANCING AUTHORITY, and the
SINK BALANCING AUTHORITY B is the RECEIVING BALANCING AUTHORITY.                        SCD

Interchange Transaction 2 (IT2)                                                                      D
BALANCING AUTHORITY A is also the SOURCE BALANCING AUTHORITY for
INTERCHANGE TRANSACTION 2 (IT2). BALANCING AUTHORITY D is the SINK
BALANCING AUTHORITY for this INTERCHANGE TRANSACTION. B and C are INTERMEDIARY BALANCING
AUTHORITY(S). The resulting INTERCHANGE SCHEDULES are from SENDING
BALANCING AUTHORITY A to RECEIVING BALANCING AUTHORITY B (SAB-        Figure 1 - Interchange
                                                                              Transactions and Schedules


Version 1                                   Int-1              Approved by OC: March 28–29, 2001
Interchange Reference Document


 ), SENDING BALANCING AUTHORITY B to RECEIVING BALANCING AUTHORITY C (SBC-IT2), and SENDING
IT2
BALANCING AUTHORITY C to RECEIVING BALANCING AUTHORITY D (SCD-IT2).

Interchange Transaction 3 (IT3)
BALANCING AUTHORITY C is the SOURCE BALANCING AUTHORITY for INTERCHANGE TRANSACTION 3
(IT3) and BALANCING AUTHORITY A is the SINK BALANCING AUTHORITY. B is the INTERMEDIARY
BALANCING AUTHORITY. To make IT3 occur, SENDING BALANCING AUTHORITY C implements an
INTERCHANGE SCHEDULE with RECEIVING BALANCING AUTHORITY B (SCB-IT3) and SENDING
BALANCING AUTHORITY B to RECEIVING BALANCING AUTHORITY A (SBA-IT3).


Net Interchange Schedule between Balancing Authorities
Using the sign convention that INTERCHANGE into a BALANCING AUTHORITY is negative and
INTERCHANGE out of a BALANCING AUTHORITY is positive, a NET INTERCHANGE SCHEDULE between
two BALANCING AUTHORITIES can be calculated that must be equal in magnitude and opposite in sign
from the perspective of each BALANCING AUTHORITY. For example, BALANCING AUTHORITY A’S NET
INTERCHANGE SCHEDULE with BALANCING AUTHORITY B is (SAB-IT1 + SAB-IT2 - SBA-IT3), BALANCING
AUTHORITY B’S NET INTERCHANGE SCHEDULE WITH BALANCING AUTHORITY A is (-SAB-IT1 - SAB-IT2 +
SBA-IT3).


Net Scheduled Interchange
The NET SCHEDULED INTERCHANGE for a BALANCING AUTHORITY is the sum of that BALANCING
AUTHORITY’S NET INTERCHANGE SCHEDULES with its ADJACENT BALANCING AUTHORITIES. The NET
SCHEDULED INTERCHANGE for BALANCING AUTHORITY A is (SAB-IT1 + SAB-IT2 - SBA-IT3), for B is (-SAB-IT1 -
SAB-IT2 + SBA-IT3 + SBC-IT2 - SCB-IT3), for C is (-SBC-IT2 + SCB-IT3 + SCD-IT2), and for D is (-SCD-IT2).


Relationship Between Balancing Authorities, Interchange Schedules, and Interchange
Transactions
Balancing      Sink        Source         Sending         Receiving             Net Interchange
Authority    Balancing    Balancing      Balancing        Balancing               Schedules
             Authority    Authority:    Authority for:   Authority for:
                for:
A           IT3          IT1, IT2       IT1, IT2         IT3              (SAB-IT1 + SAB-IT2 - SBA-IT3)
B           IT1                         IT2, IT3         IT1, IT2, IT3    (-SAB-IT1 - SAB-IT2 + SBA-IT3)      Balance
                                                                          (+SBC-IT2 - SCB-IT3)
C                        IT3            IT2, IT3         IT2              (-SBC-IT2 + SCB-IT3)             Balance
                                                                          (+SCD-IT2)
D           IT2                                          IT2              (-SCD-IT2)                 Balance




Version 1                                     Int-2                 Approved by OC: March 28–29, 2001
Interchange Reference Document


B.     Interchange Schedules within a Multi-Party Regional Agreement
       or Transmission Tariff
If BALANCING AUTHORITY(S) A, B, C, and D are parties to a transmission agreement or tariff, such as a
Regional agreement, RTO or ISO, then there is no need for the INTERCHANGE SCHEDULES from B to C or
C to D as in the previous example. In this case, all four BALANCING AUTHORITY(S) are considered
ADJACENT BALANCING AUTHORITY(S) and can schedule directly with each other. (See
Figure 2 on the right).
                                                                                                   A
Interchange Transaction 1
                                                                                       SAB = IT1       SAD = IT2
BALANCING AUTHORITY A is the SOURCE BALANCING AUTHORITY for
INTERCHANGE TRANSACTION 1 (IT1) and BALANCING AUTHORITY B is the SINK
                                                                                                   B
BALANCING AUTHORITY. To make IT1 occur, BALANCING AUTHORITY A
implements an INTERCHANGE SCHEDULE with BALANCING AUTHORITY B (SAB-IT1).               SCA = IT3
In this case, the SOURCE BALANCING AUTHORITY A is the SENDING BALANCING
AUTHORITY, and the SINK BALANCING AUTHORITY B is the RECEIVING                                     C
BALANCING AUTHORITY and these two Balancing areas are adjacent to each other.

Interchange Transaction 2                                                                          D
BALANCING AUTHORITY A is also the SOURCE BALANCING AUTHORITY for
INTERCHANGE TRANSACTION 2 (IT2). BALANCING AUTHORITY D is the SINK
BALANCING AUTHORITY for this INTERCHANGE TRANSACTION. The resulting INTERCHANGE SCHEDULE
is directly from SOURCE (SENDING) BALANCING AUTHORITY A to SINK (RECEIVING) BALANCING
AUTHORITY D (SAD-IT2).
                                                                            Figure 2 - Interchange
Interchange Transaction 3                                                   Schedules within a Multi-
BALANCING AUTHORITY C is the SOURCE (SENDING) BALANCING                     Party agreement or tariff
AUTHORITY for INTERCHANGE TRANSACTION 3 (IT3) and BALANCING
AUTHORITY A is the SINK (RECEIVING) BALANCING AUTHORITY. To make IT3 occur, SENDING
BALANCING AUTHORITY C implements an INTERCHANGE SCHEDULE directly with SINK (RECEIVING)
BALANCING AUTHORITY A (SCA-IT3).


Net Interchange Schedule between Balancing Authorities
Using the sign convention that INTERCHANGE into a BALANCING AUTHORITY is negative and
INTERCHANGE out of a BALANCING AUTHORITY is positive, a NET INTERCHANGE SCHEDULE between
two BALANCING AUTHORITIES can be calculated that must be equal in magnitude and opposite in sign
from the perspective of each BALANCING AUTHORITY. For example, BALANCING AUTHORITY A’S NET
INTERCHANGE SCHEDULE with BALANCING AUTHORITY B is (SAB-IT1), BALANCING AUTHORITY B’S NET
INTERCHANGE SCHEDULE with BALANCING AUTHORITY A is (-SAB-IT1).

Net Scheduled Interchange
The NET SCHEDULED INTERCHANGE for a BALANCING AUTHORITY is the sum of that BALANCING
AUTHORITY’S NET INTERCHANGE SCHEDULES with its ADJACENT BALANCING AUTHORITIES. The NET
SCHEDULED INTERCHANGE for BALANCING AUTHORITY A is (SAB-IT1 - SCA-IT3 + SAD-IT2), for B is (-SAB-
IT1), for C is (SCA-IT3), and for D is (-SAD-IT2).




Version 1                                   Int-3              Approved by OC: March 28–29, 2001
Interchange Reference Document


Relationship between Balancing Authority(s), Interchange Schedules, and Interchange
Transactions
Balancing     Sink       Source       Sending         Receiving        Interchange Schedules
Authority   Balancing   Balancing    Balancing        Balancing
            Authority   Authority   Authority for:   Authority for:
               for:        for:
                                                                                           Balance
A           IT3         IT1, IT2    IT1, IT2         IT3              SAD-IT2
                                                                      -SCA-IT3
                                                                      SAB-IT1
                                                                                 Balance
B           IT1                                      IT1              -SAB-IT1
C                       IT3         IT3                               SCA-IT3       Balance
D           IT2                                      IT2              -SAD-IT2




Version 1                                 Int-4               Approved by OC: March 28–29, 2001
Interchange Reference Document


C.       Implementing Interchange Schedules
1. Confirming Interchange Schedules. Interchange Schedules are confirmed between Adjacent
   Balancing Authority(s). The RECEIVING BALANCING AUTHORITY(S) are responsible for initiating
   contact with the SENDING BALANCING AUTHORITY(S); however, it is also permissible for the
   SENDING BALANCING AUTHORITY to initiate contact with the RECEIVING BALANCING AUTHORITY.




     Figure 3 on the right shows the confirmation “chain.”

2. Ramp rates. When the SENDING BALANCING AUTHORITY and
   RECEIVING BALANCING AUTHORITY implement an
                                                                                Figure 3 - Schedule confirmation
   INTERCHANGE SCHEDULE between each other, they must begin                     "chain"
   their generation adjustments at the same time using the same
   ramp rates. A mismatch of these parameters will
                                                                                      100 MWH                     100 MWH
   cause a frequency error in the INTERCONNECTION.
                                                                Tag
                                                              Submitted
3. Starting and ending times. Interchange SCHEDULES                                      100 MW




                                                                                                                                   RA
                                                                      MP




                                                                                                                                     MP
                                                                    RA




   usually start and end on the clock hour. However,
   PURCHASING-SELLING ENTITIES may wish to begin                                      1 Hour
   or end an INTERCHANGE TRANSACTION at other
                                                                       Schedule                     TIME                    Schedule
   times, and the BALANCING AUTHORITY(S) should try                    Start Time                                           End Time
   to accommodate the resulting off-hour INTERCHANGE
   SCHEDULES if possible.                                      Figure 4 - Interchange Schedule resulting from 100
                                                               MW Interchange Transaction for two hours showing
4. Interchange accounting. All BALANCING                       ramp start time and durations and energy accounting
   AUTHORITY(S) must account for their INTERCHANGE             for each hour.
   SCHEDULES the same way to enable them to confirm
   their NET INTERCHANGE SCHEDULES each day with
   their ADJACENT BALANCING AUTHORITY(S) as                   100 MW

   required in WEQBPS-005-000, “Inadvertent
   Interchange.” NERC requires “block”
   INTERCHANGE SCHEDULE accounting, which
   assumes, for energy accounting purposes, that the
                                                                       7:00    7:20      7:40     8:00     8:20     8:40    9:00       9:20

     beginning and ending ramps have zero duration.
     This, in effect, moves the energy associated with the    Figure 5 - Block accounting moves the ramp
     starting and ending ramps into their adjacent starting   energy into the adjacent clock hours.
     and ending clock hours of the INTERCHANGE
     SCHEDULE.




Version 1                                       Int-5                  Approved by OC: March 28–29, 2001
Interchange Reference Document


5. Curtailing, Canceling, or Terminating Interchange Transactions

   5.1. Curtailing Interchange Transactions

        5.1.1. Notifying the Sink Balancing                                           Interchange Curtailment,
               Authority. When a BALANCING                     Source                 Cancellation, or
               AUTHORITY, RELIABILITY                          Control Area Termination Confirmation
               AUTHORITY or TRANSMISSION
                                                            A
               OPERATOR must curtail an                                                Direct Sink-to-Source
               INTERCHANGE TRANSACTION, it                                             Control Area Confirmation of Curtailment

               begins the process by contacting its                     B                                      Sink
               RELIABILITY COORDINATOR and the                                                                 Control Area
               SINK BALANCING AUTHORITY.               Confirmation with                                 D
                                                       Adjacent Control Areas
               When a RELIABILITY COORDINATOR          on Schedule Path            C
                                                                                                            Curtailment
               curtails an INTERCHANGE                                                                      request
               TRANSACTION, it contacts all other                           Cancellation or
                                                                            Termination request                     Control Area,
               RELIABILITY COORDINATORS. Then                                                                       Transmission Provider,
               the RELIABILITY COORDINATOR of        Purchasing-Selling                                             or Security Coordinator
               the SINK BALANCING AUTHORITY                Entity
               notifies the SINK BALANCING
               AUTHORITY, the SOURCE                Figure 6 - Interchange Curtailment, Canceling, or
               BALANCING AUTHORITY, and the         Termination confirmation
               originating PURCHASE-SELLING ENTITY, and any DC Tie Operator on the scheduling
               path of the curtailment

        5.1.2. Notifying other entities. Once the SINK BALANCING AUTHORITY has been notified, it
               contacts the originating PURCHASE-SELLING ENTITY and SOURCE BALANCING
               AUTHORITY directly, confirms the curtailment and the resulting change in their
               INTERCHANGE SCHEDULES. The SINK BALANCING AUTHORITY then contacts the
               INTERMEDIARY BALANCING AUTHORITY(S) and TRANSMISSION PROVIDERS on the
               SCHEDULING PATH as well as the PURCHASING-SELLING ENTITY who submitted the tag
               (this is accomplished via the requirement that BALANCING AUTHORITY(S),
               TRANSMISSION PROVIDERS, and PURCHASE-SELLING ENTITY’S have full-time E-Tag
               monitoring). Following this notification, if the SOURCE BALANCING AUTHORITY and
               SINK BALANCING AUTHORITY are not adjacent, they begin implementing the
               INTERCHANGE SCHEDULE adjustments with their ADJACENT BALANCING AUTHORITY(S).

Canceling or Terminating Interchange Transactions. When a PURCHASING-SELLING ENTITY must
cancel an INTERCHANGE TRANSACTION before it begins, or terminates one that is in progress, the
PURCHASING-SELLING ENTITY shall contact the SINK BALANCING AUTHORITY to which it submitted the
INTERCHANGE TRANSACTION tag. The SINK BALANCING AUTHORITY shall then directly contact its
RELIABILITY COORDINATOR, all BALANCING AUTHORITY(S), and TRANSMISSION PROVIDERS on the
SCHEDULING PATH. Additional details of INTERCHANGE TRANSACTION curtailment are found in INT-
003-0 – Interchange Transaction Implementation and Policy[BDB1] 9, “Security Coordinator
Procedures.”




Version 1                                              Int-6                    Approved by OC: March 28–29, 2001
Item 9.         Functional Model – IAITF Recommendations
Pat Doran will review the Interchange Authority Implementation Task Force (IAFTF)
recommendations and discuss the follow-up actions based on those recommendations.

Roman Carter will be available via teleconference Friday morning to report on the latest
Functional Model Working Group (FMWG) actions regarding the Interchange Authority
function.

Mike Oatts will give a status report on the Coordinate Interchange Standard Drafting Team.

Actions
The Interchange Subcommittee needs to assign responsibility for the follow-up actions that are
appropriate once the Functional Model changes are adopted.



Attachment
Interchange Authority Implementation Task Force Report to the Interchange Subcommittee,
Version 1
NORTH AMERICAN ELECTRIC RELIABILITY COUNCIL
  Princeton Forrestal Village, 116-390 Village Boulevard, Princeton, New Jersey 08540-5731




    Interchange Authority Implementation
                 Task Force
 Report to the Interchange Subcommittee




                              A New Jersey Nonprofit Corporation

                  Phone 609-452-8060   Fax 609-452-9550   URL www.nerc.com
Introduction
In considering the implementation of the NERC Reliability Functional Model, the Operating
Committee charged the Interchange Subcommittee (IS) with operationally defining the
Interchange Authority (IA) function. The Interchange Authority Function Task Force (IAFTF)
was formed to compile and address the outstanding issues surrounding the IA function, and
define how the IA function would operate with the adoption of standards related to the NERC
Reliability Functional Model (FM). The IAFTF developed a white paper to define how the tasks
of an Interchange Authority could be performed operationally and how the Interchange Authority
function interrelates with other functions — both market and reliability.

When the white paper was presented to the NERC Operating Committee (OC), they requested
the Interchange Subcommittee to distribute the report as a means to solicit further comments on
the IA functionality from NAESB, the ISO/RTO Council, NERC Functional Model Working
Group, and other industry groups and to further develop detailed IA functionality and
recommendations for supporting tools.

The IS recognized that the white paper focused on implementation of the IA as defined in the
NERC Reliability Functional Model; however, but did not consider the initial implementation of
the reliability standards or the transition to version 1 standards. To address this issue and the
charge from the NERC OC, the IS formed the Interchange Authority Implementation Task Force
(IAITF) to provide recommendations on the implementation of the Interchange Authority.




IAITF Report v1.0                     Page 2 of 19                               March 10, 2005
Executive Summary
The purpose of this report is to provide recommendations on how to implement the concept of an
Interchange Authority (IA) into an industry that “operates” within the Functional Model. In
providing recommendations for the implementation of the IA, the task force focused on key
milestones to which the recommendations are aligned. The recommendations are based on the
following implementation timeframes:

   a) Near Term — Recommendations that can be put in place to support the implementation
      of the reliability standards that will take place on April 1, 2005. (All required changes
      may not be completed by this date.)
   b) Mid Term — Recommendations that can be implemented in support of the Version 1
      Coordinate Interchange Standard.
   c) Long Term — Recommendations in support of the conclusions of the Interchange
      Authority Function Task Force white paper to implement a single interconnection-wide
      IA.


               Reliability           Version 1                Industry Tool
               Standards             Standards                  Changes




               Near Term             Mid Term                  Long Term
                Actions               Actions                   Actions


Figure 1 – Recommendation Timeframes

The report provides options associated with each of the implementation milestones and identifies
considerations associated with each option. These options were only considered if they could be
applied in the time required to effectively meet the implementation milestones. The task force
recommendations include the specific action items required to implement them and the
responsible party.




IAITF Report v1.0                     Page 3 of 19                               March 10, 2005
Near Term Implementation Options
The near term options considered by the task force were limited to those solutions that could be
put in place to support the implementation of the reliability standards that will take place on
April 1, 2005 or within a reasonable period of time thereafter. The task force analyzed the results
of the mapping of IA tasks to the reliability standard requirements and used it as a means of
formulating the recommendations. In the following options, consideration was given to
functional specifications for tool changes, clarification of the reliability standards and revisions
to reference guides.

Option 1
The Sink Balancing Authority (BA) will perform the interchange tasks of the current Sink
Control Area and those associated with the Tag Authority in E-tag. The mapping in Appendix C
& D show where the IA requirements are being met in the reliability standards. Considerations:

   a) Revise the definition of the IA to remove the term “authority” and replace it with the term
      “coordinate”. Modify the definition of Interchange Authority in the Functional Model as
      follows:
      Authorizes Coordinates and communicates implementation of valid and balanced
      Interchange Schedules between Balancing Authority Areas, and ensures Interchange is
      Transactions are properly identified for reliability assessment purposes.
      In addition, the tasks of the IA should be modified to more closely reflect this definition
      as outlined in Appendix A. The relationship of the IA with other functional entities
      should be modified as shown in Appendix B.
   b) Rename the Interchange Authority to Interchange Coordinator. The formal change in
      name from IA to IC may remove some concern related to the use of the word “authority”
      and may more closely reflect actual practice and expectations.
   c) Modify the Functional Model (as identified in Appendix A & B) to include the revised IA
      tasks under the Balancing Authority. (Note: This may not require a wholesale change to
      the Functional Model. Mapping of tasks to the BA can be done with an explanatory note
      without removing the IA from the Functional Model.)
   d) Issue a letter to the industry explaining the role of the BA under the reliability standards
      and relationship to the functional model as per the above.
   e) Modify the existing Interchange Guideline as a reference document associated with the
      interchange reliability standards to clarify the role of adjacent TSP’s in ensuring a
      contiguous transmission path by including adjacent TSP’s on E-tags.




IAITF Report v1.0                      Page 4 of 19                                 March 10, 2005
Option 2
Do nothing. The interchange and tagging tasks performed by the control areas today are
performed by the Balancing Authority under the reliability standards. The IA is not a registered
entity and is not referred to in the reliability standards. Considerations:

   a) The BA as described in the functional model will not correctly refer to the interchange
      and tagging tasks being performed under the current reliability standards.
   b) The Electronic Tagging Functional Specification still refers to the role of the control area
      as the Tag Authority.




IAITF Report v1.0                     Page 5 of 19                                March 10, 2005
Mid-Term Implementation Options
The mid term options considered by the task force were limited to those solutions that could be
put in place in conjunction with the issuance of the Version 1 Coordinate Interchange Standard.
This Standard is currently under development based on the existing NERC functional model will
require further revision to coordinate with any changes to the functional model.

Option 1
Require that the organization performing the Tag Authority function register as the IA (see figure
2). The Electronic Tagging Functional Specification assigns the Tag Authority requirements to
the “entity responsible for Control Area operations”. This has been translated to the Sink BA in
the current reliability standards. Considerations:

   a) Revise the Electronic Tagging Functional Specification to reflect functional model
      language and map the Tagging Service requirements from the Control Area to the
      Interchange Coordinator (IC) performing the Interchange function for a Sink Balancing
      Authority’s organization.. (Note: This does not preclude the Balancing Authority from
      using a third party to fulfill these requirements.)
      Action: NERC IS to assign this action to TISWG. TISWG to consider the following:

              1. Updating the TSIN registry to include Functional Model entities.
              2. Impact analysis of the E-tag modifications required to implement the
                 Functional Model entities.
   b) Require registration to the revised IC entity.
   c) Revise the version 1 Coordinate Interchange Standard to reflect the modified IA (IC)
      tasks and relationships as identified in Appendix A and B.

Option 2
Revise the Coordinate Interchange Standard to reflect current day interchange and tagging
requirements. Considerations:

   a) Depending on the decision made regarding mid and long-term recommendations, either
      remove the IA from the Functional Model or leave it as a placeholder. If left as a
      placeholder until long-term recommendations are implemented, it must be made clear in
      the Functional Model that the IA entity will not be implemented under the Version 1
      Standards.
   b) Remove the “how” language from the existing reliability standard and focus on the
      “what” without using the IA terminology.




IAITF Report v1.0                     Page 6 of 19                                March 10, 2005
Long-Term Implementation Options
In considering the long-term options for implementing the Interchange Authority, the task force
focused on the option proposed by the Interchange Authority Function Task Force white paper.
Comments received on the IAFTF white paper indicate industry support for Option 3
(consolidated approach). This option would create a single NERC wide or interconnection wide
IA. Upon completion of the commercial functions as prescribed by NAESB during the Market
Period, the submitting PSE would send the completed balanced request for interchange to a
defined IA. This IA would be responsible for:

   1. Distributing the Request for Interchange (RFI) to all affected reliability entities.
   2. Obtaining confirmation of the RFI from the reliability entities.
   3. Distributing status of the confirmation process.
   4. Authorizing implementation of physical interchange by the affected BAs.
   5. Forwarding individual confirmed RFI(s) along with appropriate net interchange
      information to the appropriate reliability assessment systems e.g. Interchange
      Distribution Calculator (IDC).
   6. Maintaining records of scheduled interchange.

Option 1
The task force reviewed the issues associated with the implementation a single industry wide IA
and considered the following:

   a) Perform a cost benefit analysis of the tool changes required to implement the IA.
      Consideration should be given to both a new industry wide tool in addition to
      modifications to the existing E-tag functionality.
   b) Consider the proposed industry move to OASIS Phase II. Electronic scheduling
      associated with this tool may allow IA type functionality to be implemented.




IAITF Report v1.0                      Page 7 of 19                                 March 10, 2005
Recommendations
Near Term
The sink Balancing Authority (BA) will perform the interchange tasks of the current sink Control
Area and those associated with the Tag Authority in E-tag (see figure 2). The mapping in
Appendix C & D shows where the IA requirements are being met in the current reliability
standards. The following actions are required to accomplish this:

   a) Revise the definition of the IA to remove the term “authority” and replace it with the term
      “coordinate”. Modify the definition of Interchange Authority in the Functional Model as
      follows:
      Authorizes Coordinates and communicates implementation of valid and balanced
      Interchange Schedules between Balancing Authority Areas, and ensures Interchange is
      Transactions are properly identified for reliability assessment purposes.
      In addition, the tasks of the IA should be modified to more closely reflect this definition
      as outlined in Appendix A. The relationship of the IA with other functional entities
      should be modified as shown in Appendix B.
      Action: NERC IS to send a letter to the Functional Model Working Group requesting the
      changes to the NERC Functional Model as outlined in Appendices A & B.
   b) Rename the Interchange Authority to Interchange Coordinator. The formal change in
      name from IA to IC may remove some concern with the use of the word “authority” and
      may more closely reflect actual practice and expectations.
      Action: NERC IS to draft a letter to the Functional Model Working Group to request a
      change to the Functional Model.
   c) Modify the Functional Model (as identified in Appendix A & B) to include the revised IA
      tasks under the Balancing Authority. (Note: This may not require a wholesale change to
      the Functional Model. Mapping of tasks to the BA can be done with an explanatory note
      without removing the IA from the Functional Model.)
      Action: NERC IS to send a letter to the Functional Model Working Group requesting
      that, for the current reliability standards, the revised IA tasks as described in the above be
      mapped to the BA in the functional model.
   d) Modify the existing Interchange Guideline as a reference document associated with the
      interchange reliability standards to clarify the role of adjacent TSP’s in ensuring a
      contiguous transmission path by including adjacent TSP’s on E-tags.
      Action: NERC IS to assign this action to the Interchange Guideline Working Group.




IAITF Report v1.0                      Page 8 of 19                                March 10, 2005
Mid Term
Require that the organization performing the Tag Authority functions register as the modified IA
(IC) (see figure 2). The Electronic Tagging Functional Specification assigns the Tag Authority
requirements to the “entity responsible for Control Area operations”. This has been translated to
the Sink BA in the current reliability standards. The following actions are required to accomplish
this:

   a) Revise the Electronic Tagging Functional Specification to reflect functional model
      language and map the Tagging Service requirements from the Control Area to the
      Interchange Coordinator (IC) performing the Interchange function for a Sink Balancing
      Authority’s organization. (Note: This does not preclude the Balancing Authority from
      using a third party to fulfill these requirements.)
      Action: NERC IS to assign this action to TISWG. TISWG to consider the following:
          1) Updating the TSIN registry to include Functional Model entities.
          2) Impact analysis of the E-tag modifications required to implement the Functional
              Model entities.
   b) Require registration to the modified IA (IC) entity.
      Action: NERC IS to draft a letter to the NERC body responsible for registration,
      requesting that registration for the revised IA be completed in conjunction with the
      implementation of the Version 1 Coordinate Interchange Standard.
   c) Revise the version 1 Coordinate Interchange Standard to reflect the modified IA (IC)
      tasks and relationships as identified in Appendix A and B.
      Action: Coordinate Interchange Standards drafting team.

Long Term
The Task Force reviewed the issues associated with the implementation a single industry wide
IA and recommend that NERC consider the following:

   a) Perform a cost benefit analysis of the tool changes required to implement the IA.
      Consideration should be given to both a new industry wide tool and modifications to the
      existing E-tag functionality.
   b) Consider the proposed industry move to OASIS Phase II. Electronic scheduling
      associated with this tool may allow IA type functionality to be implemented.




IAITF Report v1.0                      Page 9 of 19                               March 10, 2005
           Appendix A

Function   Function – Balancing
           Definition
           Integrates resource plans ahead of time, and maintains load-interchange-generation
           balance within a Balancing Authority Area and supports Interconnection frequency in
           real time. Validates and approves Interchange Schedules.

           Tasks
              1. Must have control of any of the following combinations within a Balancing
                 Authority Area:

                     a. Load and Generation (an isolated system)

                     b. Load and Scheduled Interchange

                     c. Generation and Scheduled Interchange

                     d. Generation, Load, and Scheduled Interchange

              2. Calculate Area Control Error within the Balancing Authority Area.

              3. Review generation commitments, dispatch, and load forecasts.

              4. Formulate an operational plan (generation commitment, outages, etc) for
                 reliability assessment

              5. Approve Interchange Transactions from ramping ability perspective

              6. Ensure valid and balanced Interchange Transaction through BA to BA
                 confirmation.

              7. Implement interchange schedules by entering those schedules into an energy
                 management system

              8. Provide frequency response

              9. Monitor and report control performance and disturbance recovery

              10. Provide balancing and energy accounting (including hourly checkout of
                  Interchange Schedules and Actual Interchange), and administer Inadvertent
                  energy paybacks

              11. Determine needs for Interconnected Operations Services
              12. Deploy Interconnected Operations Services.
              13. Implement emergency procedures



           IAITF Report v1.0                   Page 10 of 19                               March 10, 2005
Entity   Responsible Entity – Balancing Authority
         Relationships with other Responsible Entities
         Ahead of Time
            1. Compiles load forecasts from Load-Serving Entities.
            2. Receives operational plans and commitments from Generator Operators within
               the Balancing Authority Area
            3. Determines amount required and deploys Interconnected Operations Services to
               ensure balance (e.g., amount of operating reserve, load-following, frequency
               response) in coordination with the Reliability Authority.
            4. Submits integrated operational plans (including maintenance plans from
               Generator Operators) to the Reliability Authority for reliability assessment and
               provide balancing information to the Reliability Authority for monitoring.
            5. Receives Confirms interchange schedules with Adjacent Balancing Authorities to
               assure approved, valid, and balanced Interchange Schedules. from the Interchange
               Authorities.
            6. Confirms Receives and approves interchange schedules with Interchange
               Authorities Coordinators.
            7. Confirms ramping capability with Interchange Authorities Coordinators.
            8. Implements generator commitment and dispatch schedules from the Load-Serving
               Entities and Generator Operators who have arranged for generation within the
               Balancing Authority Area. The Balancing Authority provides this commitment
               and dispatch schedule to the Reliability Authority.
            9. Provides generation dispatch to its Reliability Authority for reliability analysis.
            10. Acquires Interconnected Operations Services from Generator Owners.

         Real Time
            11. Directs resources (Generator Operators and Load-Serving Entities) to take action to
                ensure balance in real time.
            12. Directs Transmission Operator to reduce voltage or shed load if needed to ensure balance
                within its Balancing Authority Area.
            13. Receives loss allocation from Transmission Service Providers (for repayment
                with in-kind losses).
            14. Provides real-time operational information for Reliability Authority monitoring.
            15. Complies with reliability requirements specified by Reliability Authority.
            16. Informs Reliability Authority, Balancing Authority (source or sink) and
                Interchange Authorities Coordinators of Interchange Schedule interruptions (e.g.,
                due to generation or load interruptions) within its Balancing Authority Area.
            17. Directs Generator Operators to implement redispatch for congestion management
                as directed by the Reliability Authority.
            18. Requests operating information from Generator Operators.
            19. Verifies implementation of emergency procedures to Reliability Authority.
         IAITF Report v1.0                       Page 11 of 19                                  March 10, 2005
   20. Coordinates use of controllable loads with Load Serving Entities (i.e.,
       interruptible load that has been bid in as Interconnected Operations Services).
   21. Implements emergency procedures as directed by the Reliability Authority.

After the hour
    22. Confirms Interchange Schedules with Interchange Authorities Adjacent Balancing
        Authorities after the hour for “checkout.”

   23. Confirms Actual Interchange with adjacent Balancing Authorities after the hour
       for “checkout.”




IAITF Report v1.0                     Page 12 of 19                               March 10, 2005
           Appendix B
Function
Function   Function – Interchange
           Definition
           Authorizes Coordinate implementation of valid and balanced Interchange Schedules
           between Balancing Authority Areas, and ensures communication of Interchange
           Transactions are properly identified for reliability assessment purposes.

           Tasks
              1. Determine Consolidate evaluations of valid, balanced, Interchange Schedules
                 (validation of sources and sinks, transmission arrangements, interconnected
                 operations services, etc.).

              2. Verify Collect ramping capability confirmations of the source and sink Balancing
                 Authority Areas for requested Interchange Schedules

              3. Collect and disseminate Interchange Transaction approvals, changes, and denials

              4. Authorize Communicates Interchange Transaction approval for implementation of
                 Interchange Transactions

              5. Enter Communicate Interchange Transaction information into Reliability
                 Assessment Systems (e.g., the Interchange Distribution Calculator in the Eastern
                 Interconnection)

              6. Maintain record of individual Interchange Transactions




           IAITF Report v1.0                   Page 13 of 19                              March 10, 2005
Entity   Responsible Entity – Interchange Authority Coordinator
         Relationships with other Responsible Entities
         Ahead of Time
           1. Verifies ramping capability for requested Interchange Schedules with Balancing
               Authorities. Note: this step is redundant to step 5 and can be deleted.

            1. Receives requests from Purchasing-Selling Entities or Balancing Authorities to
               implement Interchange Transactions.

            2. Submits all Interchange Transaction requests to the Reliability Authorities,
               Balancing Authorities, and Transmission Service Providers for approvals.

            3. Receives confirmation from Transmission Service Providers of transmission
               arrangement(s).

            4. Receives confirmation from Balancing Authorities of the ability to meet ramping
               requirements for submitted Interchange Transactions Schedules.

            5. Receives confirmation from Reliability Authorities based on reliability analysis
               for submitted Interchange Transactions.

            6. Receives information from Balancing Authorities of expected Interconnected
               Operations Services deployments that result in an Interchange Transaction (for
               example, an Interchange Schedule that is enabled by reducing load in a Balancing
               Authority Area, which frees up resources.)

            7. Informs Purchasing-Selling Entities on implementation of load-provided
               Interconnected Operations Services that were bid into the market that result in an
               Interchange Transaction. Note: It is the markets responsibility to submit a
               proposed interchange transaction. Communication to all entities involved is
               covered under step below.

            7. Provides approved, valid, and balanced Interchange Schedules Communicates
            final approval or denial of Interchange transactions to the Balancing Authorities,
            Transmission Service Providers, Reliability Authorities, and Purchase Selling Entities
            for implementation.
         Real Time
            7. Provides Transmission Service Providers with the requested Interchange
               Transactions received from Purchasing Selling Entities using that Transmission
               Service Providers’ transmission system. Note this is redundant to step 2.

            8. Receives curtailments and redispatch implementation from Reliability
               Authorities.

            9. Informs Transmission Service Providers, Purchasing-Selling Entities, Reliability
               Authorities, and Balancing Authorities of Interchange Schedule Implementations
               and Curtailments. Note Implementation is performed by the BA. Notification of
               approval is covered in step 7.


         IAITF Report v1.0                    Page 14 of 19                               March 10, 2005
   10. Receives information on Interchange Schedule interruptions due to generation
       loss or load interruption from the Balancing Authorities and communicates the
       Interchange Schedule status to Balancing Authorities, Transmission Service
       Providers, Reliability Coordinators and Purchase-Selling Entities.

After the hour
   11. Maintains and provides records of individual Interchange Transactions for the
       Balancing Authorities.




IAITF Report v1.0                    Page 15 of 19                              March 10, 2005
Appendix C — Mapping of IA Functions

                                                                                                    Responsible
Function #              Description                 Reliability Standard Requirement                   Entity
IA 1         Determine valid, balanced,          Done in a distributed fashion using E-tag.         TSP, Sink BA,
             Interchange Schedules                                                                  TOP
             (validation of sources and sinks,
             transmission arrangements,
             interconnected operations
             services, etc.).
IA 2         Verify ramping capability of the    INT-002-0 R3.3                                     BA
             source and sink Balancing           INT-003-0 R1.3
             Authority Areas for requested       INT-003-0 R1.1.3
             Interchange Schedules
IA 3         Collect and disseminate             INT-003-0 R1                                       Sink BA
             Interchange Transaction
             approvals, changes, and denials
IA 4         Authorize implementation of         INT-002-0 R2                                       TSP, BA
             Interchange Transactions            INT-002-0 R3
                                                 INT-002-0 R5
                                                 INT-003-0 R4

IA 5         Enter Interchange Transaction       INT-002-0 R 1.4. The Sink Balancing Authority      Sink BA
             information into Reliability        shall ensure that all tags and any modifications
             Assessment Systems (e.g., the       to tags are provided via a secure network to the
             Interchange Distribution            following entities on the Scheduling Path:
             Calculator in the Eastern           Security Analysis Services (IDC or other
             Interconnection)                    regional reliability tools).
IA 6         Maintain record of individual       Maintained in E-tag for 90 days                    Tag Authority
             Interchange Transactions                                                               Service




             IAITF Report v1.0                      Page 16 of 19                                   March 10, 2005
      Appendix D — Interchange Coordinator (IC) Mapping to
      Reliability Standards
INT-001-0 R 3.    The Balancing Authority or Purchasing Selling Entity responsible for submitting
                  the tag shall submit all tags to the Sink Balancing Authority (IC) according to
                  timing tables in Attachment 1-INT-001-0.
INT-002-0 R 1.    The Sink Balancing Authority (IC) shall ensure that all tags and any modifications
                  to tags are provided via a secure network to the following entities on the Scheduling
                  Path:
INT-002-0 R 4.    Each Balancing Authority and Transmission Service Provider on the Scheduling
                  Path shall communicate their approval or denial of the Interchange Transaction to
                  the Sink Balancing Authority (IC).
INT-002-0 R 5.    Upon receipt of approvals or denials from all of the individual Balancing
                  Authorities and Transmission Service Providers, the Sink Balancing Authority (IC)
                  shall communicate the composite approval status of the Interchange Transaction to
                  the Purchasing-Selling Entity and all other Balancing Authorities and Transmission
                  Service Providers on the Scheduling Path and through the Reliability analysis
                  service to affected Transmission Operators and Reliability Coordinators.
INT-003-0 R 4.    The Sink Balancing Authority shall be responsible for initiating implementation of
                  each Interchange Transaction as tagged. Upon receiving composite approval from
                  the Sink Balancing Authority (IC), each Balancing Authority on the scheduling
                  path shall enter confirmed schedules into its ACE equation
INT-004-0 R 1.    If a Reliability Coordinator, Transmission Operator, or Source or Sink Balancing
                  Authority, due to a reliability event, needs to modify an Interchange Transaction
                  that is in progress or
                  scheduled to be started, the entity shall, within 60 minutes of the start of the
                  emergency Transaction, modify the Interchange Transaction tag, and shall
                  communicate the modification to the Sink Balancing Authority (IC).
INT-004-0 R 3.    Upon receipt of modification to an Interchange Transaction as described in
                  Requirement R1, the Sink Balancing Authority (IC) (Source Balancing Authority in
                  the case of a loss of generation)
                  shall communicate the modified information about the Interchange Transaction,
                  including its composite approval status, to all Balancing Authorities and
                  Transmission Service Providers on the Transaction path and the Purchasing-Selling
                  Entity responsible for the Transaction.
INT-004-0 R 4.    At such time as the reliability event allows for the reloading of the transaction, the
                  entity that
                  initiated the curtailment shall release the limit on the Interchange Transaction tag to
                  allow reloading the transaction and shall communicate the release of the limit to the
                  Sink Balancing Authority (IC).




      IAITF Report v1.0                   Page 17 of 19                                March 10, 2005
            Purchasing Selling Entity                   Agent
                                                        Agent                                   IDC
                                                        Service                               iIDC / ID
                                                       Service

                                                    Notify


                                                      Authority
                                                       Authority                 Imple-      Reliability
                                                                                             Security
            Sink Balancing Authority                                                        Coordinator
                                                        Service
                                                       Service                   mented     Coordinator
                                                    Notify           Approve
                                                                     or Deny
          Transmission Providers and                                                        Tag submitted
          Balancing Authorities on                    Approval
                                                       Approval                             by Agent Service
          Scheduling Path                               Service
                                                       Service                              Transaction approved
                                                                                            by Approval Service




Figure 2 – Tagging Services




                                                      Reliability                    Curtailment
                                                    Coordinator or
                                                    Transmission
                                                                               (Stop, Reduce, or Hold)
                                                     Provider or
                                                      Balancing
                                                      Authority



                                                      Notifies



                                                        Sink
                                                      Balancing
                                                      Authority



                No Approval Return
                                                        Notifies




            Source      Balancing     Balancing                            Trans          Trans        Trans
           Balancing    Authority 2   Authority n                          Prov           Prov         Prov
           Authority                                                         1              2            n



                                                     Implement



Figure 3 – Tag Curtailment




IAITF Report v1.0                              Page 18 of 19                                                   March 10, 2005
                         Sending/Source
                         Balancing Authority
                    A

                                     Receiving/Sending
                                     Intermediary Balancing Authorities
                        B

                                                          D
                                    C                  Receiving/Sink
                                                       Balancing Authority


Figure 4 – BA to BA Schedule Confirmation




IAITF Report v1.0                 Page 19 of 19                              March 10, 2005
Item 10.        Dynamic Transfer Catalog
Background
At its March 2004 meeting, the OC asked the Interchange Subcommittee to prepare a new
Dynamic Transfer Catalog


Discussion
Gordon Scott will lead the discussion on the NERC Dynamic Transfer Catalog Project and data
collection format.


Actions
The Interchange Subcommittee needs to draft a letter requesting the regions to begin collecting
the data required for a dynamic transfer catalog. The purpose of this catalog is to identify
transfers that are not tagged, but handled dynamically. This information will allow the reliability
coordinators to have a more accurate understanding of flows during normal and emergency
conditions.



Attachments
•   Dynamic Transfer Catalog Project Overview Statement Executive Summary

•   Data collection form
                       Project Overview Statement
                           Executive Summary

Project Name:               Dynamic Transfer Catalog
Department:                 Operations
Last Updated:               02/14/05
Author:                     Bill Blevins
Project Manager(s):
Executive Sponsor: Don Benjamin
Project Department Owner: Operations



Project Business Case

 Project Overview

  [The Interchange Subcommittee intends to catalog the Interconnection Dynamic Transfers occurring
  in the interconnections and establish a means for reviewing new transfers for approval.]
  •   Interchange Subcommittee intends to propose a review process for the implementation of new Dynamic Transfers.
  •   The Interchange Subcommittee would propose that a task force or working group be established, with members from
      the IS, IDCWG, RS, ORS and RS to oversee the review process.



 Issue/Opportunity

      -    [This project is a result of a request from the NERC Operating Committee Meeting after
           the NERC Interchange Subcommittee reviewed the August 14, 2003, AIE – E-Tag audit results
           and identified some of the same inconsistencies between the AIE Net Scheduled Interchange
           and the E-Tag information in IDC as those noted in the audit responses from the Control
           Areas in the physical representation of the load or generation in E-Tag versus the Control
           Area responsibility for that load or generation reflected in AIE survey.]


  •   the projected Dynamic Schedule and revisions in E-Tag versus the integrated Dynamic Schedule in AIE survey
  •   Point-to-point transactions internal to a Control Area
  •   DC Ties
  •   Reserve Sharing events less than a hour
  •   Mid-hour changes in E-Tag
  •   Self-provided losses in the E-Tag

Confidential
10A Dynamic Transfer Catalog Project Overview Statement Executive Summary.doc
Last printed 5/12/2005 2:10:00 PM
                                Project Overview Statement—Executive Summary


  Project Goal

  [The Interchange Subcommittee will review the data to ensure among other items that:]
  •   Entities are accounting for transfers in the same way
  •   Transfers are handled correctly in the ACE equations
  •   Transfers that should be tagged are tagged




Primary Project Objectives

  Primary Project Objectives

  [Correct the Identified dynamic Transfer Issues related to the Aug 13th Blackout and develop a
  means to better ensure Dynamic Transfers are implemented properly.]
  •   Catalog Existing Transfers
  •   Develop a Technical Group to approve Dynamic Transfers in a similar manner to the Bias setting requirement
      by the Resources Subcommittee to ensure proper Bias setting methodology.



Project Benefits

  Project Benefits

  [The key benefit is to enable the IDC to more accurately provide the reliability information to
  users.]
  •   Ensure Dynamic Transfers are adequately modeled and coordinated
  •   Ensure Dynamic Schedules are properly tagged



Primary Project Deliverables

  Milestone 1
  •   Develop Dynamic Transfer Survey
  •   Send out Survey with Instructions to the regions
  •   Catalog Transfers



  Milestone 2
  •   Send final Catalog of Dynamic Schedules to IDCWG/RS/IS/ORS
  •   Technical committees review catalog
  •   Resolve Technical Questions
  •   Publish Catalog to Reliability Authority/Reliability Coordinator/Interchange Authority


  Milestone 3
  •   Form Technical Review Group
  •   Compare AIE results to eTag
  •   Report to OC




Project Interdependencies and Inputs

Confidential                                              Page 2                                          5/12/2005
                               Project Overview Statement—Executive Summary


  Project Interdependencies and Inputs

  [Standardization/Cooperation.]
  •   Standard Survey
  •   Regional Collections
  •   Technical Reviews




Project Conditions

  Project Assumptions

  [Committee Responsibilities.]
  •   Interchange Subcommittee will review eTag Issues
  •   IDCWG will review catalog will review Pseudo Ties and Dynamic Schedules to determine transmission
      modeling issues
  •   ORS will review Joint Unit issues
  •   Resources Subcommittee will review Catalog and determine ACE impact

  Project Issues

  [Technical and Political.]
  •   Existing transfers are modeled and require time to correct
  •   Tariffs




Project Critical Success Factors (Key Performance Indicators)

  Project Critical Success Factors

  [Completion of Identified needs]
  •   Development of Catalog for Technical Committee reviews
  •   Development of Process fro registering new dynamic transfers
  •   Successful presentation of Catalog Project to OC




Project Duration Estimates

 Project Milestone                                      Date Estimate             Confidence Level

 Project Start Date                                     02/14/05                  High

 Milestone 1                                            04/01/05                  Medium

 Milestone 2                                            06/01/05                  Medium

 Milestone 3                                            10/01/05                  Medium

 Project End Date                                       N/A                       High




Confidential                                           Page 3                                             5/12/2005
                       Project Overview Statement—Executive Summary




APPROVALS


Prepared By    ______________________________________
               Project Manager

Approved By ______________________________________
            Project Sponsor

               ______________________________________
               Executive Sponsor

               ______________________________________
               Client Sponsor




Confidential                             Page 4                       5/12/2005
               Native                                           Intermediary   Intermediary   Intermediary   Intermediary   Intermediary     Attaining
 Pseudo       Balancing                                           Balancing      Balancing      Balancing      Balancing      Balancing      Balancing
 Type ID      Authority   Psuedo Type   Max Value   Min Value    Authority 1    Authority 2    Authority 3    Authority 4    Authority 5     Authority




               Source                                           Intermediary   Intermediary   Intermediary   Intermediary   Intermediary
 Dynamic      Balancing    Dynamic                                Balancing      Balancing      Balancing      Balancing      Balancing    Sink Balancing
Schedule ID   Authority     Type        Max Value   Min Value    Authority 1    Authority 2    Authority 3    Authority 4    Authority 5      Authority
Item 11.       Future Meetings


Attachment
Interchange Subcommittee meetings for 2005.
Interchange Subcommittee Meeting Schedule — 2005

            Date         Location              Comment
May 18–20          Cincinnati, OH    All meetings are half-full-half:
                                     1–5 p.m. first day
                                     8 a.m.–5 p.m. second day
                                     8 a.m.–noon third day
August 24–26       Québec City, QU
November 16–18     New Orleans, LA

				
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