Southwest Power Pool BOARD OF DIRECTORS/MEMBERS …Southwest Power Pool BOARD OF DIRECTORS/MEMBERS...

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Southwest Power Pool BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING Hilton Palacio Del Rio, San Antonio, TX January 30, 2007 - Summary of Action Items - 1. Approved minutes of the October 24, December 1 and December 12, 2006 Board of Directors/Members Committee meetings. 2. Approved the Finance Committee’s recommendation to engage Price Waterhouse Coopers to perform a Type II SAS70 audit of SPP’s controls surrounding transmission and imbalance energy services. 3. Approved the Strategic Planning Committee’s recommendation to modify the Delegation Agreement between NERC and SPP to change the allocation of ERO and RE costs from Balancing Areas in the SPP footprint to all the load serving entities in the SPP footprint. 4. Approved the Markets and Operations Policy Committee’s recommendation for proposed changes to Tariff Section 34, Tariff changes for PRRs and endorsement of the RTWG’s two-point recommendation regarding cost allocation method changes and approval of proposed changes to Tariff Attachments J and S. With respect to PRR134, the Finance Committee will reconsider 6 months after implementation with the objective of reinstating or reducing the 5-day period. 5. Approved the Markets and Operations Policy Committee’s recommendation of revisions to Criteria 7.1 to reflect changes to satisfy new NERC standards PRC-002-01 and PRC-018-01. 6. Approved the Markets and Operations Policy Committee’s recommendation to endorse the 2006 – 2016 Transmission Expansion Plan and the list of reliability projects in Appendix ‘B’. 7. Approved the Markets and Operations Policy Committee’s recommendation to endorse the list of Base Plan Upgrades consistent with the intent of the Tariff, “Option C”, and “Transition Plan of Option C.” 8. Approved the Markets and Operations Policy Committee’s recommendation of the Westar waiver to such extent that this project is fully Base Plan funded for the Rose Hill – Sooner 345 kV project. 9. Approved, contingent on approval from RSC, the Markets and Operations Policy Committee’s recommendation that the OG&E Reservation 1032973 designated as Centennial Wind Farm with a waiver amount recommended by the SPP staff of $747,000.

Transcript of Southwest Power Pool BOARD OF DIRECTORS/MEMBERS …Southwest Power Pool BOARD OF DIRECTORS/MEMBERS...

Southwest Power Pool

BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING

Hilton Palacio Del Rio, San Antonio, TX

January 30, 2007

- Summary of Action Items - 1. Approved minutes of the October 24, December 1 and December 12, 2006 Board of Directors/Members

Committee meetings. 2. Approved the Finance Committee’s recommendation to engage Price Waterhouse Coopers to perform a Type

II SAS70 audit of SPP’s controls surrounding transmission and imbalance energy services. 3. Approved the Strategic Planning Committee’s recommendation to modify the Delegation Agreement between

NERC and SPP to change the allocation of ERO and RE costs from Balancing Areas in the SPP footprint to all the load serving entities in the SPP footprint.

4. Approved the Markets and Operations Policy Committee’s recommendation for proposed changes to Tariff

Section 34, Tariff changes for PRRs and endorsement of the RTWG’s two-point recommendation regarding cost allocation method changes and approval of proposed changes to Tariff Attachments J and S. With respect to PRR134, the Finance Committee will reconsider 6 months after implementation with the objective of reinstating or reducing the 5-day period.

5. Approved the Markets and Operations Policy Committee’s recommendation of revisions to Criteria 7.1 to

reflect changes to satisfy new NERC standards PRC-002-01 and PRC-018-01. 6. Approved the Markets and Operations Policy Committee’s recommendation to endorse the 2006 – 2016

Transmission Expansion Plan and the list of reliability projects in Appendix ‘B’. 7. Approved the Markets and Operations Policy Committee’s recommendation to endorse the list of Base Plan

Upgrades consistent with the intent of the Tariff, “Option C”, and “Transition Plan of Option C.” 8. Approved the Markets and Operations Policy Committee’s recommendation of the Westar waiver to such

extent that this project is fully Base Plan funded for the Rose Hill – Sooner 345 kV project. 9. Approved, contingent on approval from RSC, the Markets and Operations Policy Committee’s

recommendation that the OG&E Reservation 1032973 designated as Centennial Wind Farm with a waiver amount recommended by the SPP staff of $747,000.

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Southwest Power Pool

BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING

Hilton Palacio Del Rio, San Antonio, TX

January 30, 2007 Agenda Item 1 - Administrative Items SPP Chair Mr. Jim Eckelberger called the meeting to order at 8:05 a.m. The following Board of Directors/Members Committee members were in attendance, via teleconference, or represented by proxy:

Mr. Larry Altenbaumer, director Ms. Phyllis Bernard, director Mr. Nick Brown, director Mr. Harry Dawson, Oklahoma Municipal Power Authority Mr. Kevin Easley, Grand River Dam Authority Mr. Jim Eckelberger, director Mr. Tom Grennan, Kansas Electric Power Cooperative Ms. Trudy Harper, Tenaska Power Services Company Mr. Quentin Jackson, director Mr. Rob Janssen, Redbud Mr. Jeff Knottek, City Utilities of Springfield Mr. Joshua Martin, director Mr. Mel Perkins, OG+E Electric Services Mr. Gary Roulet, Western Farmers Electric Cooperative Mr. Harry Skilton, director Mr. Stuart Solomon, American Electric Power Mr. Richard Spring, Kansas City Power & Light Mr. Tom Stuchlik, Westar Mr. Rick Tyler, Northeast Texas Electric Cooperative Mr. Gary Voigt, Arkansas Electric Cooperative Corporation

Mr. Eckelberger asked for a round of introductions. There were 67 persons in attendance either in person or via phone representing 30 members (Attendance List - Attachment 1). Mr. Brown reported that there were no proxies and a quorum was declared. Mr. Eckelberger referred to draft minutes of the October 24, December 1 and December 12, 2006 meetings. He asked that the following corrections be made to the December 12 minutes: the word “October” be struck in his statement concerning alternative health benefits on page 3; and in regards to the SAS70 controls on page four, the word “members” when referring to active and non-active members be replaced by “committee.” Mr. Eckelberger then asked for additional corrections or a motion for approval (10/24/06, 12/1/06 & 12/12/06 Meeting Minutes - Attachment 2). The minutes were approved by acclamation as revised. Mr. Eckelberger introduced and welcomed Ms. Jennifer Amerkhail an Energy Industry Analyst for FERC. Agenda Item 2 – Corporate Governance Committee Report Mr. Nick Brown reported that the Corporate Governance Committee (CGC) met via teleconference on January 12 to fill two vacancies on the SPP Members Committee. Mr. Stuart Solomon (AEP) was elected to fill Mr. Nick Akins’ position in the TO/IOU sector and Mr. Rob Janssen (Redbud) was elected to fill Mr. Jim Stanton’s position in the TU/IPP Marketer sector. Mr. Brown stated that the CGC would meet soon to start the nominating process for October to fill expiring terms.

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He asked that the committee meet with Ms. Stacy Duckett and himself during the first break in today’s meeting to choose a face-to-face meeting date to start this process and review organizational surveys. Agenda Item 3 – President’s Report Mr. Nick Brown provided the SPP President’s report (2006 4Qtr Report – Attachment 3). Mr. Brown stated that it was 39 hours and 44 minutes until the SPP EIS Market goes live on February 1. The Go/No Go team will meet today at 2:00 p.m. and tomorrow, January 31, at 2:00 p.m. to make its final recommendation. Should the team decide a no go, Mr. Brown will call the Board of Directors/Members Committee for a teleconference to aid in the final decision. He invited anyone interested to attend the event at midnight Wednesday night. Please let SPP know if you plan to attend in order to arrange entry. Mr. Eckelberger and Mr. John Rogers (FERC) will be present. Mr. Carl Monroe offered that there is a go/no go status report on the SPP website daily. All Market metrics from October through December have been completed. There have been some concerns expressed regarding late arrival of model changes, settlement data feeds, LIP volatility, etc. but some things will only be learned after going live. Mr. Brown stated that SPP currently has two initiatives underway:

1. NERC’s transition to an Electric Reliability Organization (ERO) The 60 day period for FERC’s response to NERC’s ERO implementation status and SPP’s RE status ends on March 10. It is hoped that SPP’s order will be issued prior to March 10; however, SPP is already assuming duties of an RE. Billings have gone out to REs under the new organization using a different mechanism with costs much higher than in the past. The mandatory compliance deadline is June 1 after which penalties will be enforced. SPP’s first initiative after achieving RE status will be to modify the Bylaws to elect three trustees to oversee the Standard setting process and the compliance process; also, additional SPP Staff will be required. Recommendations from Members to fill the trustee positions would be welcome and helpful. SPP must transition quickly following the receipt of the order.

2. SPP’s Transmission Expansion Plan (STEP) This initiative will be covered in the Regional State Committee (RSC) report presented later in the meeting by RSC President, Ms. Julie Parsley.

Mr. Brown then presented a review of the Executive Quarterly Report, 4Q 2006. He pointed out that 100 employees had been hired in 2006 making a total of 245 with 300 employees budgeted for 2007. With a need for additional engineers, SPP is actively working with universities to aid in training programs. Currently SPP has a program with the University of Arkansas at Little Rock and now is exploring membership in a newly formed group called the National Center for Reliable Electric Transmission at the University of Arkansas. In further discussion regarding the quarterly report, Ms. Trudy Harper requested that charts regarding Tariff administration on pages 33 and 34 report volume of firm and non-firm requests. Agenda Item 4 – Regional State Committee Report President Julie Parsley presented the Regional State Committee (RSC) report. The RSC agenda included reports, updates and discussion on the following items:

• The RSC held a Technical Conference January 28 – 29 on regional integrated resource planning and demand response. Materials from this conference will be posted on the SPP website.

• An update was given on the NERC ERO/RE transition. RSC expressed concern that there is a process in place with FERC to monitor the ERO/RE budget.

• RSC is under budget due in part to the fact that no studies have been conducted. • An RSC audit was conducted. In regards to travel expenses, mileage and reimbursement for mileage

needs to be more accurate. • CAWG reported on economic upgrades offering four alternatives. RSC felt SPP should move forward with

a portfolio and recovery methodology in parallel with RSC, which will develop methodology for economic upgrades. Soon the group will be meeting on a monthly basis and have set a goal to present a plan to the RSC by years end.

• Adopted point 1and 2 of an RTWG recommendation as approved by MOPC regarding unintended

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consequences. Point 1 is to change the inter-zonal cost allocation process to “the sum of the Positive (rather than net) MW-Mile impacts” and point 2 is a minimum allocation of $100,000 is implemented to a zone. RSC did not approve point 3, which is to give further consideration to altering the existing regional/zonal allocation percentages and/or allocation methods for Base Plan Funded projects to encourage the construction of high voltage projects that have both economic and reliability benefits.

• Reviewed the SPP Transmission Expansion Plan. • Approved the Westar waiver request for the Rose Hill – Sooner 345 kV project. • Les Dillahunty reviewed the SPP Board evaluation, the SPP Stakeholder Survey, and the SPP Emergency

Response Plan. Mr. Nick Brown reported on an additional item regarding contract services. SPP is evaluating the aggregate study process and considering offering alternative study services as a contract service. Mr. Michael Desselle and Mr. Les Dillahunty are asked to develop a business plan. Other services that may be evaluated for contract services are: transmission planning, generation interconnection and standards compliance. Agenda Item 5 – Federal Energy Regulatory Commission Report Mr. John Rogers provided an update on FERC activities:

• The Commission issued SPP’s Market Readiness Certification Order on Friday, January 26. • The Commission will convene a conference on its market monitoring policies on April 5 in Washington,

D.C. • The first Demand Response conference was held in Miami at the NARUC annual meeting in November. • The first in a series of conferences will be held at the Commission to examine the state of competition in

wholesale power markets on February 27. • Two significant rule makings are currently before the Commission: 1) Open Access Transmission Tariff

reform and 2) Market Based Rates. • An invitation was extended to visit the FERC website, which now provides electric market information

overviews for the nation as well as regional markets, including all of the RTO/ISOs.

Agenda Item 6 – Finance Committee Report Mr. Harry Skilton provided a Finance Committee report (Finance Committee Report & Recommendations – Attachment 4). Mr. Skilton reported that the committee would be meeting immediately following the Board meeting to discuss: the Financial Policy, CapEx financing, requirements for 2007 financials, modify Tariff wording for credit settlements dates, and negligence provisions of the Tariff. Mr. Skilton provided background regarding SAS70 audits. Price Waterhouse Coopers (PwC) performed the Type I SAS70 audit testing controls on a specific date in 2005 and 2006. A Type II audit requires testing controls for a six month period. The committee decided that a Type II audit will be performed May 1 – October 31, 2007. Mr. Skilton moved for the Board to approve: Recommend to SPP’s Board of Directors the engagement of Price Waterhouse Coopers to perform a Type II SAS70 audit of SPP’s controls surrounding transmission and imbalance energy services. Mr. Jackson seconded the motion. The Members were in unanimous favor. The motion passed. The Finance Committee will discuss a request to provide interim status reports during the audit process. Mr. Eckelberger inquired about SAS70 corrections referred to at the December 12 meeting. The committee will inquire and report back. Agenda Item 7 – Human Resources Committee Report Mr. Quentin Jackson stated that the Human Resources Committee report would be presented in Executive Session.

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Agenda Item 8 – Compliance Committee Report Mr. Josh Martin provided the Compliance Committee report. The committee met on December 11 and reviewed several items:

• Continue to register new entities in the region that will be subject to ERO compliance; 125 entities are expected.

• SPP will host a Compliance Workshop on February 13-14 in Tulsa. • No new requests for inquiry have been submitted to the Market Monitor. • Work is continuing to fine tune required market monitoring reports. • Approved the 2007 contract for Boston Pacific to continue as the External Market Advisor. A filing will be

made with FERC following the Board meeting. • The Committee has reviewed its Organizational Effectiveness Survey results.

Agenda Item 9 – Strategic Planning Committee Report Mr. Richard Spring provided the Strategic Planning Committee report (SPC Report – Attachment 5) addressing organizational effectiveness initiatives, Strategic Plan prioritization results and schedule, and the ERO/RE cost allocation. Mr. Spring provided background regarding the Regional Entity (RE) funding. NERC is now authorized to collect the costs associated with operating the Electric Reliability Organization (ERO). In December 2006, NERC sent the 1st quarter 2007 invoices for assessment for the ERO and Southwest Power Pool Regional Entity dues. Errors were found, and Balancing Authorities (BA) were concerned that they do not have arrangements to pass the NERC costs on to other Load Serving Entities (LSE) within their BA. Mr. Spring requested approval of the following recommendation: The Strategic Planning Committee recommends modifying the Delegation Agreement between NERC and SPP to change the allocation of ERO and RE costs from Balancing Areas in the SPP footprint to all the load serving entities in the SPP footprint. Mr. Brown moved to approve the SPC recommendation. Mr. Skilton seconded the motion. The Members were in unanimous favor. The motion passed. Mr. Spring asked that the Staff be authorized to take appropriate actions consistent with the recommendation. Following discussion, it was decided that the Markets and Operations Policy Committee (MOPC) should check the definition and find a uniform calculation of Net Energy for Load (NEL) values. Mr. Spring stated that NERC will bill in two weeks and urged all to pay as usual and rely on a true up later. Mr. Spring mentioned the newsletter “The Org Report.” This is a communication tool that will be distributed monthly via email. The report provides an overview of what is taking place in SPP’s committees and working groups. If you wish to continue to receive this publication, an exploder has been set up and you must subscribe in order to continue service. Agenda Item 10 – Markets and Operations Policy Committee Report Mr. Eckelberger announced that Ms. Robin Kittel has assumed other responsibilities within Xcel and has resigned as Markets and Operations Policy Committee Chair. He announced that he has appointed Mr. John Olsen (Westar) to serve as Chair. Mr. Olsen presented the Markets and Operations Policy Committee report (MOPC Report and Recommendations – Attachment 6). MOPC action items were presented: Regional Tariff Working Group (RTWG) Recommendations Mr. Dennis Reed presented background and a recommendation for approval regarding Tariff Section 34; PRR’s 129, 132, 134, and 135; and Inter-Zonal Cost Allocation Endorsement – Unintended Consequences. The RSC approved the first two points of the Unintended Consequences recommendation but not the third point. Mr.

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Brown moved to approve the following recommendation:

Approve the proposed changes to Tariff Section 34, Tariff changes for PRRs, endorsement of the RTWG’s three-point recommendation regarding cost allocation method changes and approval of proposed changes to Tariff Attachments J and S.

Mr. Jackson seconded the motion. Mr. Skilton moved to amend:

With respect to PRR134 the Finance Committee will reconsider this change 6 months after its implementation with the objective of reinstating or reducing the 5-day period.

Ms. Bernard seconded the amendment. The Members were in unanimous favor. The motion for the amendment passed. Following discussion, Mr. Skilton moved to amend the motion to remove point 3 of the cost allocation method changes. Mr. Martin seconded the amendment. The Members were in favor with Ms. Harper in abstention. The motion passed. A vote was called for the original motion as amended. The Members were in unanimous favor. The motion passed. SPCWG Recommendation – Criteria 7.1 NERC adopted revised Protection Reliability Standards in August 2006. As a result, the System Protection & Control Working Group and the MOPC are recommending Board approval of:

Recommend that the MOPC approve revision of Criteria 7.1 to reflect changes to satisfy new NERC standards PRC-002-01 and PRC-018-01

Mr. Brown moved to approve revision of Criteria 7.1. Ms. Bernard seconded the motion. The Members were in unanimous favor. The motion passed. 2006 – 2016 SPP Transmission Expansion Plan Mr. Olsen reviewed the 2006 - 2016 Transmission Expansion Plan and requested approval of two recommendations:

1. Endorse the 2006-2016 SPP Transmission Expansion Plan for SPP Board of Directors approval. a. Achieves requirements of Attachment O. b. Assesses the reliability and economic operation of the SPP Transmission System as

required. c. The TWG supports this recommendation.

2. Endorse the list of reliability projects in Appendix ‘B’

a. Supports SPP BOD approval to maintain reliability. b. SPP BOD will authorize and direct the start of construction. c. The TWG supports this recommendation.

Mr. Skilton moved to approve. Ms. Bernard seconded the motion. The Members were in unanimous favor. The motion passed. Mr. Eckelberger commended Mr. Jay Caspary and the SPP committees and working groups for a job well done.

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SPP OATT 1.3h “Base Plan Upgrades” SPP Staff reviewed the list of all identified transmission reliability upgrades from the SPP Transmission Expansion Plan and evaluated them in accordance with “Option C” and “Transition Plan to Option C”. MOPC requests that the Board endorse the list of Base Plan Upgrades consistent with the intent of the tariff, “Option C”, and “Transition Plan to Option C.” Mr. Brown moved for approval. Mr. Altenbaumer seconded the motion. The Members were in unanimous favor. The motion passed. Westar Waiver Mr. Olsen provided background regarding the Westar’s waiver request for the Rose Hill – Sooner 345 kV project. The MOPC recommends: Approval of the Westar waiver to such extent that this project is fully Base Plan funded. Mr. Brown moved for approval. Mr. Martin seconded the motion. The Members were in favor with Jeff Knottek, Rob Janssen and Harry Dawson in abstention. The motion passed. OG&E Waiver Mr. Olsen provided background regarding the OG&E waiver request. The MOPC recommends: the OG&E Reservation 1032973 designated as Centennial Wind Farm with a waiver amount recommended by the SPP staff of $747,000, be approved. In discussion, it was determined that the RSC had not voted on the OG&E waiver but would hold a teleconference to do so. Mr. Altenbaumer moved to approve the motion contingent upon approval by the RSC. Ms. Bernard seconded the motion. The Members were in favor with Jeff Knottek in abstention. The motion passed. Mr. Olsen finished with information items including project tracking, VRLs, Market Working Group post go live discussions, transmission operating directives, and MOPC action on Transmission Operating Directives. The FERC representatives excused themselves from the meeting during VRL discussions. Mr. Eckelberger suggested that VRLs need to be monitored and discussions held on how non-market events affect the market. He proposed a face to face Board of Directors/Members Committee meeting in 4 – 6 weeks for such discussions. Future Meetings The next regularly scheduled Board of Directors meeting is April 24 in Oklahoma City. Adjournment With no further business, Mr. Eckelberger thanked everyone for participating and adjourned the meeting to Executive Session at 1:05 p.m. Executive Session The Board of Directors approved the Human Resources Committee recommendation for funding of the 2006 Performance Compensation Plan and the president’s compensation. Stacy Duckett, Corporate Secretary

Southwest Power Pool

BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING January 30, 2007

Hilton Palacia Del Rio, San Antonio, Texas • A G E N D A •

8:00 a.m. – 3:00 p.m. CST

1. Administrative Items.................................................................... Mr. Jim Eckelberger

2. Corporate Governance Committee Report .......................................... Mr. Nick Brown

3. President’s Report ............................................................................... Mr. Nick Brown

4. Regional State Committee Report .................................................... Ms. Julie Parsley

5. FERC Report .....................................................................................Mr. John Rogers

6. Finance Committee Report ................................................................Mr. Harry Skilton

7. Human Resources Committee Report ........................................ Mr. Quentin Jackson

8. Compliance Committee Report ............................................................Mr. Josh Martin

9. Strategic Planning Committee Report............................................ Mr. Richard Spring

10. Markets and Operations Policy Committee Report ............................. Ms. Robin Kittel

11. Future Meetings........................................................................... Mr. Jim Eckelberger

a. April 24 Oklahoma City

b. June 11 – 12 Little Rock

c. July 24 Kansas City

d. October 30 Tulsa

e. December 11 Dallas

Executive Session

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Southwest Power Pool

BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING

Doubletree Hotel at Warren Place – Tulsa, OK

October 24, 2006

- Summary of Action Items - 1. Approved minutes of the September 29 and July 25, 2006 Board of Directors/Members Committee meetings. 2. Approved the Markets and Operations Policy Committee’s recommendation 1) of “unusual circumstances”

exist in the OG&E waiver and recommended an extension in the 120-day deadline to the end of January 2007 and 2) the recommendation that SPP staff present and discuss its recommendation on the waiver request to CAWG for their directions prior to the MOPC January 2007 meeting.

3. Approved the Markets and Operations Policy Committee’s recommendation that construction of various

reliability upgrades, already presented to the Board of Directors, that need to be started immediately. 4. Approved the Markets and Operations Policy Committee’s recommendation to request a 60 day extension to

file the Schedule 2 Tariff changes with an effective date of January 1, 2007. 5. Approved the Strategic Planning Committee’s recommendation to approve the Strategic Plan with delegation

of responsibilities to SPP organizational groups, prioritize initiatives and develop an implementation plan for approval by the Board.

6. Approved the Compliance Committee’s recommendation to authorize staff to file appropriate comments

related to the compliance enforcement program proposed by NERC for the Regional Entity. 7. Approved the Human Resources Committee’s recommendation to amend the retirement plan to reduce

retirement benefits for participants in the Plan by 6% per year for every year that retirement begins in advance of normal retirement age.

8. Approved Finance Committee’s recommendation to engage BKD, LLC to audit and report on SPP’s financial

statements for the year ending December 31, 2006. 9. Approved the Board of Director’s recommendation to consider at its December 12, 2006 meeting,

implementation of the EIS market on February 1 with certification of readiness on January 1.

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Southwest Power Pool

BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING

Doubletree Hotel at Warren Place – Tulsa, OK

October 24, 2006 Agenda Item 1 - Administrative Items SPP Chair Mr. Jim Eckelberger called the meeting to order at 8:50 a.m. The following Board of Directors/Members Committee members were in attendance, via teleconference, or represented by proxy:

Mr. Stuart Solomon, for Mr. Nick Akins, American Electric Power Mr. Larry Altenbaumer, director Ms. Phyllis Bernard, director Mr. Nick Brown, director Mr. Harry Dawson, Oklahoma Municipal Power Authority Mr. Kevin Easley, Grand River Dam Authority Mr. Jim Eckelberger, director Mr. Tom Grennan, Kansas Electric Power Cooperative Ms. Trudy Harper, Tenaska Power Services Company Mr. Quentin Jackson, director Mr. Jeff Knottek, City Utilities of Springfield Mr. Joshua Martin, director Mr. Mel Perkins, OG+E Electric Services Mr. Gary Roulet, Western Farmers Electric Cooperative Mr. Harry Skilton, director Mr. Richard Spring, Kansas City Power & Light Mr. Jason Atwood, for Mr. Jim Stanton, Calpine Mr. Tom Stuchlik, Westar Mr. Rick Tyler, Northeast Texas Electric Cooperative Mr. Ricky Bittle, for Mr. Gary Voigt, Arkansas Electric Cooperative Corporation

Mr. Eckelberger asked for a round of introductions. There were 81 persons in attendance either in person or via phone representing 30 members (Attendance List - Attachment 1). Mr. Brown reported proxies and a quorum was declared (Proxies - Attachment 2). Mr. Eckelberger referred to draft minutes of the July 25 and September 29, 2006 meetings and asked for corrections or a motion for approval (7/25/06 & 9/29/06 Meeting Minutes - Attachment 3). Mr. Jackson moved that the minutes be approved as presented. Mr. Martin seconded the motion, which passed. Agenda Item 2 – Regional State Committee Report RSC President, Denise Bode presented the Regional State Committee (RSC) report. The RSC agenda included reports, updates and discussion on the following items:

• Election of Officers: Julie Parsley, President; Brian Moline, Vice President; and Sandra Hochstetter, Secretary/Treasurer

• Approved the RSC Budget for 2007 and 2008. • A Technical Conference planned in conjunction with the January SPP Board of Directors meeting. Joyce

Davidson and Les Dillahunty will plan this conference with the help of Commissioner Bode. • Dr. Mike Proctor presented the Cost Allocation Working Group report regarding proposed revisions to

Attachment Z of the Tariff. • Mr. Les Dillahunty provided an EIS market status report. The RSC suggested that a delay in market

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implementation was fine but that an implementation date be set. • Mr. Dennis Reed provided a report regarding Base Plan projects. • Mr. Les Dillahunty explained waiver requests. The RSC agreed that waiver requests should be flexible to

allow new projects. Mr. Eckelberger thanked Commissioner Bode for her two years of leadership in the RSC and welcomed Commissioner Parsley as the new RSC president. Agenda Item 3 – Federal Energy Regulatory Commission Report Tony Ingram (FERC) provided an update on FERC activities: FERC recently voted orders addressing:

• Loss compensation methodology requiring that all generators providing this service should be compensated

• Market participant agreement and reserve cost allocation • An order on rehearing of its March, 2006 order regarding SPP’s energy imbalance market

Pending Commission action items are:

• Balancing Authority settlement agreement • SPP’s filing of a meter agent agreement and market readiness metrics including a statutory action item

Other recent Commission actions include: • Approval of NERC’s proposed ERO budget and 83 ERO reliability standards • Approval of the funding of NERC ERO statutory activities, under EPAct 2005 and funding of Regional

Entitiy statutory activities through the ERO • Issuance of a final rule addressing PURPA requirements

Agenda Item 4 – Markets and Operations Policy Committee Report Ms. Robin Kittel presented the Markets and Operations Policy Committee report (MOPC Report and Recommendations – Attachment 4). MOPC action items were reviewed:

• PRR’s 094, 104 and 106 were approved unanimously as presented by the Market Working Group (MWG). • Reviewed waiver requests as allowed in Attachment J of the SPP Tariff from Oklahoma Gas and Electric

(OG&E) and Golden Spread Electric Cooperative (GSEC), The OG&E request was denied and GSEC withdrew its request. MOPC made the following recommendation for Board approval: MOPC recommended to the Board of Directors that “unusual circumstances” exist in the OG&E waiver and that the MOPC is recommending an extension in the 120-day deadline to the end of January 2007. MOPC also requested Board concurrence on: MOPC directed SPP Staff to present and discuss its recommendation on the OG&E waiver request, in addition to the criteria used to evaluate a waiver, to the CAWG for their direction and recommendation prior to the next MOPC meeting in January 2007. Mr. Brown moved to approve and offer concurrence to this recommendation. Mr. Jackson seconded the motion. The Members were in unanimous favor. The motion passed.

• MOPC approved the Business Practices Working Group proposed change to Business Practice 4.1, which

addresses RTO-SS timing vs. NERC timing requirements, making them the same. • MOPC task forces met via teleconference to review all material as a follow up on an initial report to the

Board of Directors in September. Ms. Kittel reviewed the Settlements Task Force and Operations Task Forces reports and recommendations.

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Mr. Dennis Reed provided information regarding Unintended Consequences and changes to Schedule 2 of the Tariff. The Regional Tariff Working Group (RTWG) formed the Interzonal Cost Allocation Task Force (IZATF) to review Unintended Consequences options. This group is to report back to the RTWG in order for RTWG to present a final recommendation to the MOPC, RSC and BOD in January. This delay is causing a delay in construction of reliability projects. The MOPC voted unanimously to request the Board: Approve the construction of the various reliability upgrades, already presented to the Board of Directors, that need to be started immediately so the upgrades can be completed when necessary to either meet reliability concerns or requests for transmission service. Mr. Jackson moved to approve MOPC’s recommendation. Mr. Skilton seconded the motion. The Members were in unanimous favor. The motion passed. Mr. Reed reviewed changes to Schedule 2 regarding Reactive Power Compensation and impacts to the Tariff. The revisions are almost complete with the exception of the impact analysis. The MOPC recommends for Board approval: MOPC directed SPP Staff to make a filing on the Schedule 2 Tariff Changes and ask for a 90-day extension of FERC with instructions to the RTWG to proceed in working on the tariff language. Mr. Skilton moved to approve the MOPC recommendation. Mr. Jackson seconded the motion. Following discussion, Ms. Bernard moved to add an amendment: Request that the effective date FERC sets be as if SPP had filed on time. Mr. Altenbaumer seconded the motion. Following discussion, Ms. Bernard revised her amendment to read: Request an effective date of January 1, 2007. Mr. Altenbaumer concurred. The Members voted in favor with Mr. Harry Dawson and Ms. Trudy Harper in opposition and Mr. Jason Atwood in abstention. The motion passed. Mr. Skilton revised his motion to request a 60-day extension with Mr. Jackson in agreement. The Members voted in favor with Mr. Harry Dawson, Ms. Trudy Harper and Mr. Jason Atwood in opposition. The motion passed. Agenda Item 5 – Strategic Planning Committee Report Mr. Richard Spring provided the Strategic Planning Committee report. After providing background, he presented the final draft of the Strategic Plan (Strategic Plan – Attachment 5). The committee recommends: The Strategic Planning Committee recommends that the SPP Board of Directors adopt the proposed Strategic Plan included in this report, and authorize the delegation of responsibilities to SPP organizational groups also contained herein under the coordination oversight of the Strategic Planning Committee and the Markets and Operations Policy Committee. Upon approval by the Board of Directors, the Committee will prioritize the initiatives in the Plan. After the Committee prioritizes the initiatives in the Strategic Plan, SPP Staff will develop an implementation plan for approval by the Board. The implementation plan will include quarterly reporting regarding the progress of these strategic initiatives. Mr. Skilton moved to approve the Strategic Plan. Mr. Martin seconded the motion. The Members voted in favor with Mr. Jason Atwood in abstention. Mr. Spring reported that regarding the organizational effectiveness, the self assessments and surveys were complete. A report will be presented to the Board of Directors at the December meeting. Agenda Item 6 – Compliance Committee Report Mr. Josh Martin provided the Compliance Committee report. The committee met in Dallas on September 28 and reviewed several items:

• Efforts continue to engage and register Regional Entities that will be subject to the ERO Compliance program.

• SPP will host a Compliance Workshop in Tulsa, Oklahoma on October 31 - November 1, 2006. • SPP staff has visited with new FERC staff members regarding a reorganization that impacts the

monitoring function.

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• Reviewed the schedule of various reports that staff will provide as part of the market monitoring function, ranging from daily to monthly reports.

• Reviewed the External Market Monitoring (EMM) function for 2007. A scope of work will be developed for the EMM and a contract presented for consideration at the next meeting.

• The Regional Entity Delegation Agreement filing was discussed with regards to the proposed appeals process. The committee proposed the following recommendation (RE Delegation Agreement Filing – Attachment 6): The Compliance Committee recommends authorization to staff to file appropriate comments related to the compliance enforcement program proposed by NERC for the Regional Entity. Mr. Martin moved approval of this recommendation. Mr. Altenbaumer seconded the motion. The Members were in unanimous favor. The motion passed.

Mr. Martin stated that the committee’s next meeting will be December 11 in Dallas, Texas. Agenda Item 7 – Human Resources Committee Report Mr. Quentin Jackson provided the Human Resources Committee report. Mr. Jackson stated that two items would be presented to the Board, one requiring executive session following the meeting. The second recommendation included the early retirement subsidy provisions (Human Resources Recommendation – Attachment 7). SPP engaged Osborn, Carreiro & Associates to perform an actuarial analysis of the Plan’s early retirement provision following a set of guidelines. As a result of this analysis, Mr. Jackson moved to approve the following recommendation:

The SPP Human Resources Committee recommends an amendment to the Plan to reduce retirement benefits for participants in the Plan by 6% per year for every year that retirement begins in advance of normal retirement. Additionally, the following employees would be in a grandfathered group that would continue to be eligible for early retirement benefits with a 2% per year reduction in benefits for every year that their retirement begins in advance of their normal retirement age:

• Employees who are age 45 or greater with at least five years of service or more at the time of adoption of the amended early retirement provision.

• Employees who were employed by SPP on January 1, 1996 and remain employees of SPP at the time of adoption of the amended early retirement provisions.

Ms. Bernard seconded the motion. The Members were in unanimous favor. The motion passed.

Mr. Jackson highlighted other items covered at the October 16 meeting including: SPP Pension Plan; SPP management 360˚ evaluation program; and implementing an SPP hotline, which was determined as not necessary at this time.

Agenda Item 8 – Finance Committee Report Mr. Harry Skilton provided a Finance Committee report (Finance Committee Report & Recommendations – Attachment 8). Issues requiring approval are:

2006 Financial Audit BKD, LLC was engaged to audit SPP’s 2005 financial statements and accounting practiced. Estimated fees to perform the 2006 audit will total $53,000. The audit would begin in mid-December, 2006 with a final report presented to the Board of Directors at the April, 2007 meeting. Mr. Skilton moved: The SPP Board of Directors approve engagement of BKD, LLC to audit and report on SPP’s financial statements for the year ending December 31, 2006. Mr. Martin seconded the motion. The Members were in unanimous favor. The motion passed.

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2007 Operating and Capital Budgets Mr. Skilton provided an overview of SPP’s 2007 Budget including initiatives in the project descriptions and analysis. Mr. Skilton moved to approve the 2007 SPP operating and capital budgets as submitted. Mr. Altenbaumer seconded the motion. The Members were in unanimous favor. The motion passed.

2007 Administrative Fee The administrative fee is determined by dividing the net revenue requirement (NRR) by the estimated billing determinants which results in the MWh rate. SPP requires a minimum rate of 19¢/MWh to ensure positive operating cash balances during the 2007 fiscal year based on the budget assumptions. Mr. Skilton moved: The Finance Committee recommends the SPP Board of Directors adopt an assessment rate and tariff administrative fee (schedule 1) of 19¢/MWh beginning on January 1, 2007. Mr. Altenbaumer seconded the motion. The Members were in unanimous favor. The motion passed.

Agenda Item 9 – EIS Market Implementation Certification Mr. Craig Roach, Boston Pacific, presented an assessment of Locational Incremental Pricing (LIP) Volatility (LIP Volatility Presentation – Attachment 9). Mr. Roach addressed the causes of LIP Volatility and recommended mitigation including: decreasing the penalty factors; allowing flexibility on effective limits for flowgates; and encouraging market participation for the good of the market. Mr. Eckelberger announced that due to the shortness of time, those not involved in the executive session were dismissed for lunch and the remainder would convene in executive session to be followed by lunch. Executive Session The Human Resources Committee (HRC) sought guidance from the Board regarding possible revisions to the SPP pension plan. Such guidance was provided; the HRC will proceed and provide a recommendation when appropriate. Agenda Item 9 – Continued Mr. Mark Rossi, Gestalt, provided an assessment of SPP Market Readiness Metrics (Readiness Metrics Report – Attachment 10). Current metrics were assessed, reduced due to duplicates, and sorted into tiers. Mr. Rossi recommended that a finite number of metrics should be tracked and a status report given on a regular basis. It is believed that this organization of metrics provides better communication and transparency of the current status critical to ensure SPP’s readiness. Other observations made included: direct linkage between outstanding and open issues, continued efforts to stabilize the systems and processes, continue to test its failover procedures, and making a conscious decision on what to do if the current location is not accessible. Mr. Lanny Nickell provided an EIS Market Status report (EIS Market Status – Attachment 10). Recent deployment tests have shown significant improvement, improved stability of market systems has been observed and improved accuracy of the short-term load forecast with some concerns remaining. There remain concerns about system stability Other concerns are the potential for excessive LIP volatility and market participants who have indicated they will not be ready for a December 1 launch. Mr. Eckelberger offered a list of actions to ensure SPP’s ability to certify conditional readiness for market implementation on December 1. Following much discussion, Mr. Eckelberger moved to:

Notify FERC that the SPP Board of Directors will not file to certify a December 1 market start date and will consider a January 1 certification at its December 12 meeting for a February 1, 2007 market start date.

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SPP executive staff is to report to the BOD/MC midway between October 24 and December 12. SPP staff is to form an action plan to address the recommendations presented during the October 24 meeting and submit that plan to the membership for review and comment prior to the plan’s finalization.

Mr. Skilton seconded the motion. The Members voted in favor with Mr. Jason Atwood in opposition and Mr. Harry Dawson in abstention. Future Meetings The next Board of Directors meeting is December 12 in Dallas, Texas. Adjournment With no further business, Mr. Eckelberger thanked everyone for participating and adjourned at 2:44 p.m. Stacy Duckett, Corporate Secretary

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Southwest Power Pool

BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING

Teleconference

December 1, 2006

- Summary of Action Items -

1. Approved the Market and Operations Policy Committee’s recommendation regarding Tariff language

for PRR128. 2. Approved the Regional Tariff Working Group’s recommended Schedule 2 revisions.

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MINUTES NO. 108

Southwest Power Pool

BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING

Teleconference

December 1, 2006 Agenda Item 1 - Administrative Items SPP Chair Mr. Jim Eckelberger called the meeting to order at 1:35 p.m. The following Board of Directors/Members Committee members were in attendance or represented by proxy:

Mr. Stuart Solomon, for Mr. Nick Akins, American Electric Power Mr. Larry Altenbaumer, director Ms. Phyllis Bernard, director Mr. Nick Brown, director Mr. Harry Dawson, Oklahoma Municipal Power Authority Mr. Jim Eckelberger, director Mr. Tom Grennan, Kansas Electric Power Cooperative Ms. Trudy Harper, Tenaska Power Services Company Mr. Quentin Jackson, director Mr. Jeff Knottek, City Utilities of Springfield Mr. Joshua Martin, director Mr. Mel Perkins, OG+E Electric Services Mr. Gary Roulet, Western Farmers Electric Cooperative Mr. Harry Skilton, director Mr. Richard Spring, Kansas City Power & Light Mr. Dennis Reed, for Mr. Tom Stuchlik, Westar Mr. Gary Voigt, Arkansas Electric Cooperative Corporation Mr. Rob Janssen, for Mr. Walt Yeager, Duke Energy Americas

Mr. Eckelberger asked for introductions. There were 33 persons in attendance via phone representing 17 members (Attendance List - Attachment 1). Mr. Brown reported proxies and a quorum was declared (Proxies - Attachment 2). Agenda Item 2 – MOPC Recommendation for Tariff Language Modifications Ms. Robin Kittel reported (MOPC Recommendations – Attachment 3) that the Market and Operations Policy Committee (MOPC) approved Tariff language associated with PRR128 with a recommendation for Board approval. Mr. Brown moved to approve Tariff language as presented. Mr. Skilton seconded the motion. The Members voted in favor with three in abstention. The motion passed. Ms. Kittel reported MOPC action on PRR125 to address FERC compliance requests. The MOPC approved PRR125 contingent upon an Operating Reliability Working Group’s (ORWG) review for any NERC compliance issues which review is to occur in advance of the December 12 Board of Directors meeting and providing a report at that meeting. It was recommended to consider the vote of MOPC and allow ORWG to review, taking action at the December 12 meeting or approving with the contingency as MOPC had. Following discussion, Mr. Eckelberger asked Ms. Kittel as MOPC Chair to assure that joint efforts occur between ORWG, Market Working Group (MWG), and Regional Tariff Working Group (RTWG) in reviewing compliance issues so that the Board of Directors can vote on the Tariff language at the December 12 meeting. It was determined that it was unnecessary to advise FERC of this status. Ms. Kittel reported MOPC actions associated with the Schedule 2 filing. Mr. Carl Monroe provided additional historical background on the process around this issue. The MOPC did not pass RTWG’s recommendation for

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Schedule 2 revisions. Following discussion of the issues, it was determined that steps would be taken to assure Market Monitor functions include review of any potential manipulation of voltage schedules assignments to generating units. Mr. Brown moved to approve RTWG’s recommendation as presented to the MOPC. Mr. Skilton seconded the motion. The Members Committee voted in favor with two in opposition. The motion passed. Adjournment With no further business, Mr. Eckelberger thanked everyone for participating and adjourned at 3:09 p.m. Stacy Duckett, Corporate Secretary

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BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING

DFW Airport Hyatt, Dallas, Texas

December 12, 2006

- Summary of Action Items -

1. Approved the Market and Operations Policy Committee’s recommendation regarding Tariff language

for PRR125. 2. Approved that SPP file for certification with FERC for a February 1 market go-live date.

3. Approved Human Resources Committee’s recommendation to amend the SPP defined benefit

retirement plan that defines earnings as base compensation only.

4. Approved SPP committee and working group rosters.

5. Approved that the Strategic Planning Committee take on the responsibility for coordinating and overseeing the process for developing recommendations from the Organizational Effectiveness Meeting.

6. Approved the Board’s recommendation that Mr. Jim Eckelberger continue to serve as Chair and Mr.

Harry Skilton as Vice Chair for another two year term to be reviewed at the end of 2007.

7. Reappointed SPP officers for 2007: Mr. Nick Brown – President and CEO Mr. Carl Monroe – Senior Vice President and COO Ms. Stacy Duckett – Vice President, General Counsel and Corporate Secretary Mr. Tom Dunn – Vice President and CFO Mr. Les Dillahunty – Vice President Regulatory Policy Mr. Michael Desselle – Vice President Process Integrity and CAO

8. Approved the Strategic Planning Committee’s recommendation to apply for NERC membership in

Sector 11, Regional Reliability Organization/Regional Entity, before the December 15 deadline.

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MINUTES NO. 109

Southwest Power Pool

BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING

DFW Airport Hyatt, Dallas, Texas

December 12, 2006 Agenda Item 1 - Administrative Items SPP Chair Mr. Jim Eckelberger called the meeting to order at 1:35 p.m. The following Board of Directors/Members Committee members were in attendance or represented by proxy:

Mr. Stuart Solomon, for Mr. Nick Akins, American Electric Power Mr. Larry Altenbaumer, director Ms. Phyllis Bernard, director Mr. Nick Brown, director Mr. Harry Dawson, Oklahoma Municipal Power Authority Mr. Kevin Easley, Grand River Dam Authority Mr. Jim Eckelberger, director Mr. Tom Grennan, Kansas Electric Power Cooperative Ms. Trudy Harper, Tenaska Power Services Company Mr. Quentin Jackson, director Mr. Jeff Knottek, City Utilities of Springfield Mr. Joshua Martin, director Mr. Mel Perkins, OG+E Electric Services Mr. Gary Roulet, Western Farmers Electric Cooperative Mr. Harry Skilton, director Mr. Richard Spring, Kansas City Power & Light Mr. Tom Stuchlik, Westar Mr. David Brian, for Mr. Rick Tyler, Northeast Texas Electric Cooperative Mr. Gary Voigt, Arkansas Electric Cooperative Corporation Mr. Rob Janssen, for Mr. Walt Yeager, Duke Energy Americas

Mr. Eckelberger asked for introductions. There were 53 persons in attendance or via phone representing 20 members (Attendance List - Attachment 1). Mr. Brown reported proxies and a quorum was declared (Proxies - Attachment 2). Mr. Brown introduced Jamie Simler, Deputy Director of the FERC Office of Energy Markets and Reliability, and welcomed her to the meeting. Mr. Brown also expressed appreciation to Mr. Eckelberger and his wife for opening their home for a reception the previous evening. Agenda Item 2 – EIS Market Implementation Mr. Carl Monroe provided an update on the EIS Market stability issues. There have been periodic lock-ups in the Market Operating System (MOS). Each vendor had people on site to check systems and offer recommendations. System upgrades were performed, data base changes made, and patches applied. The system has been running for 8 days with no problems. The Stability Task Force is winding down and it is felt has accomplished what is needed. Mr. Mark Rossi provided a review of the market readiness metrics (Market Metrics Presentation – Attachment 3). Mr. Rossi presented a snapshot status of the 27 go-live metrics being tracked through December 10. He reported that the total number of open issues is showing a downward trend.

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Mr. Michael Desselle reviewed the SPP Market implementation go-live issues list (SPP Market Go-Live Issues List – Attachment 4). Mr. Desselle pointed out that yellow certification items include: short-term load forecast, system stability, and revenue neutrality. He provided a report on the December 7 and 11 deployment tests and a list of additional deployment tests scheduled through January 2007. SPP has received has received participant concerns from ACES Power Marketing and AEP. Mr. Gary Roulet stated that many of ACES concerns had been taken care of. Ms. Phyllis Bernard felt that even though responses to the ACES letter were being taken care of through the organizational group process, a written letter would provide closure. Mr. Desselle informed the group that the Operations Reliability Working Group (ORWG) met today, December 12 and passed PRR 125 with one negative vote. The MOPC had approved PRR 125 modifications for filing pending ORWG review for any conflicts with NERC standards. The MOPC recommends the Board approve filing and seek a waiver of the 60 day requirement. John Olsen (Westar Energy), Vice Chair of MOPC, confirmed via phone and was available to answer questions. Mr. Brown moved to approve modifications of PRR 125 and to seek a waiver of the 60 day requirement. Mr. Skilton seconded the motion. The Members voted in favor with Mr. Tom Stuchlik in opposition. The motion passed. Mr. Perkins requested a depiction of the Violation Relaxation Limit (VRL) and wanted to know how it would impact system. Mr. Brown moved to file certification with FERC for a February 1 market go live date. Mr. Altenbaumer seconded the motion. The Members were in unanimous favor. The motion passed. Agenda Item 3 – Human Resources Committee Report Mr. Quentin Jackson provided the Human Resources Committee Report (HRC Report and Recommendation – Attachment 5). In October, the HRC became aware of an unintended consequence in the implementation of the performance compensation plan, which included performance compensation payments in the calculation of pension payments upon retirement. Guidance was requested from the Board at the October meeting. The Board/Members Committee suggested that the pension plan should be amended to clarify that pension payments will be based on base compensation only. The committee was asked to provide a recommendation. Mr. Jackson stated that Mr. Tom Dunn presented the staff’s position at the November 29 HRC meeting, which was not in favor of the change as it would further erode the company’s Benefit Program which had been recognized as the gold standard in the industry. Mr. Brown defended the staff position stating that the current plan was needed as a competitive hiring tool and offers morale in competing to fill 45 positions. Mr. Jackson moved to approve the recommendation, passed unanimously by the HRC committee:

The Human Resources Committee recommends the SPP Board of Directors approve an amendment to the SPP defined benefit retirement plan that defines earnings as base compensation only, excluding performance compensation payments, bonuses, or other forms of compensation in the calculation of retirement benefits.

Mr. Skilton seconded the motion. The Members voted in favor with two abstentions. The motion passed. Mr. Eckelberger stated that he hoped alternative health benefits would be explored due to October revisions cutting back on retirement health benefits. Agenda Item 4 – Organizational Effectiveness Review BOD Evaluation Mr. Nick Brown provided a review of the Board of Directors evaluation (BOD Evaluation – Attachment 6). The Corporate Governance Committee is required to conduct Board of Directors evaluation annually. This is SPP’s third survey. The survey was sent to Board Members, Members Committee representatives, and the Markets and

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Operations Policy Committee chair. Fifteen completed surveys were received. Mr. Brown encouraged everyone to participate in the future in order to be more effective. Mr. Eckelberger requested that directors be invited to member sites when meetings are in their locale so as to better understand member perspectives. Mr. Altenbaumer requested more input from members in the future. Mr. Brown was asked to provide the 2005 results in order to compare (BOD Evaluation 2005 – Attachment 7). Stakeholder Satisfaction Survey Results Mr. Michael Desselle reviewed the stakeholder satisfaction survey results (Stakeholder Satisfaction Survey – Attachment 8). This is the second Stakeholder Satisfaction Survey. The survey results are one metric in the employee performance compensation plan. Mr. Eckelberger suggested building action plans to respond to concerns that are repetitive. These results will go to the Human Resources Committee for their consideration for performance compensation. Organizational Group Rosters Ms. Stacy Duckett provided organizational group rosters for review (SPP Rosters – Attachment 9). Every two years rosters are to be reviewed and approved by the Board to assess an equal representation of companies and sectors. Mr. Skilton moved to approve SPP rosters. Mr. Altenbaumer seconded the motion. The Members were in unanimous favor. The motion passed. SAS70 Controls Mr. Tom Dunn provided a report on the SAS70 Audit. SPP has received the results of the SAS70 Type ll Audit conducted in 2006. There were two qualifications which are not believed to be substantial, and 5 qualifications for computer control and IT functions that will take more effort. Staff assures that corrections will be made in the next couple of months. A copy of the audit will be distributed to active members. Non-active members will need to request a copy. Mr. Skilton stated that the Finance Committee will have a recommendation for the Board in January to perform the next SAS70 audit. Organizational Group Annual Assessment Mr. Richard Spring reviewed the Organizational Group Annual Assessment report (Organizational Group Assessment – Attachment 10). Group surveys and self-assessments were performed for the period from August 2005 – July 2006. On November 9 and 10 group chairs and secretaries met for a workshop to review the results both positive and negative, review meeting costs, and brainstormed developing suggestions for improvement and recommendations for the 2007 survey. Mr. Spring recommended the Board approve:

Strategic Planning Committee will be given the responsibility for coordinating and overseeing the process for developing recommendations in response to priority issues and categories resulting from the Organizational Effectiveness Meeting.

Mr. Brown moved to approve the SPC recommendation as presented. Mr. Jackson seconded the motion. The Members were in unanimous favor. The motion passed. Mr. Spring stated that the SPC will develop a framework, assign items to groups, and develop a process for recommendations at its January meeting. A report will be presented to the Markets and Operations Policy Committee (MOPC) for comment on January 16 – 17 and then presented to the Board on January 30. Metrics Development Mr. Michael Desselle reviewed the development of organizational metrics (Metrics Development – Attachment 11). A Metrics Task Force has been created and a scope will be developed for approval. Mr. Larry Altenbaumer will chair this task force and Mr. Desselle will be the staff secretary. Members of the task force include: Mr. Harry Skilton, Director; Mr. Mel Perkins, OG&E; Ms. Robin Kittel, Xcel Energy; Mr. Gary Voigt, AECC; and Ms. Trudy Harper, Tenaska. The purpose of this task force is to develop organizational develop measurements to assure that SPP is operating effectively and efficiently and to the benefit of its stakeholders. The Metrics Task Force will

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report to the Board of Directors. Mr. Quentin Jackson stated that historically the chair and vice chair of the Board of Directors change every 2 years. With all that is happening in the company, this is not the time for a change of Board leadership. Mr. Jackson moved that Mr. Jim Eckelberger serve as Chair and Mr. Harry Skilton as Vice Chair for a two year term to be reviewed at the end of 2007. Mr. Brown seconded the motion. The Members were in unanimous favor. The motion passed. Mr. Eckelberger stated that a precedent had been set to reappoint the SPP officers annually and moved that the following officers be reappointed:

Mr. Nick Brown – President and CEO Mr. Carl Monroe – Senior Vice President and COO Ms. Stacy Duckett – Vice President, General Counsel and Corporate Secretary Mr. Tom Dunn – Vice President and CFO Mr. Les Dillahunty – Vice President Regulatory Policy Mr. Michael Desselle – Vice President Process Integrity and CAO

Mr. Skilton seconded the motion. The Members were in unanimous favor. The motion passed. Agenda Item 5 – ERO/RE Membership Sector Election Mr. Richard Spring provided information regarding the ERO/RE Membership Sector election (ERO/RE Membership Sector Recommendation – Attachment 12). The North American Electric Reliability Council Board of Trustees has approved the transition of the Council to its successor, the North American Electric Reliability Corporation (NERC). SPP is eligible to join the Membership in one of two sectors: 1) Sector 10, Independent system operator/regional transmission organization; or 2) Sector 11, Regional reliability organization/regional entity. The Strategic Planning Committee (SPC) recommends the following elements for SPP to become a member of NERC:

1. That SPP should apply to become a member of NERC; 2. That SPP select Sector 11, Regional Reliability Organization/Regional Entity, as being consistent

with its business interest; 3. That Staff complete the online application form consistent with this direction before the December

15th deadline; and, 4. That Staff submit a nomination to become a voting member of the MRC in the Regional reliability

organization/regional entity sector. Mr. Brown moved for approval of the recommendation as presented. Mr. Skilton seconded the motion. The Members were in unanimous favor. The motion passed. Workshops are planned to discuss registration and cost recovery for the SPP region on February 28. Agenda Item 6 – Situation Response Plan Mr. Michael Desselle provided a review of the SPP Emergency Response Plan (Emergency Response Plan – Attachment 13). This plan was created by an inter-departmental team of employees. The SPP plan contains some original content and some gathered from other successful plans. Major areas of focus included:

• Internal Coordination • Crisis Communication • Information Systems Incident Response

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• Emergency Situations • Building Evacuation (all employees) • Operations Evacuation to Backup Center • Power System Restoration

An implementation plan has been developed with plans for training and drills in 2007. Adjournment With no further business, Mr. Eckelberger thanked everyone for participating and adjourned at 11:59 p.m. Stacy Duckett, Corporate Secretary

17 of 101

SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT

4Q 2006

SUMMARY

4Q 2006 3Q 2006 2Q 2006 1Q 2006 4Q 2005

Tariff Administration Service, Fees & Assessments

$57.3M (YTD)

$42.8M $28.2M $14.6M $52.6M

Operating Expenses $64.1M (YTD)

$45.9M $29.1M $13.1M $46.4M

Operating Cash Flow $10.1M (YTD)

$0.9M $6.2M $6.1M $12.9M

Cash on Hand $28.2M

(12/31/06)$25.8M $35.6M $38.9M $42.1M

TLR Events 67 244 160 61 37

Tags (daily average) 416 543 582 432 451

Transmission Service Requests 36,090 51,695 48,564 36,567 37,388

Transmission Service Study Queue

434 requestsfor studies

439 requests

316 requests 110/103 174/157

Generation Interconnection Queue

52 requests 45requests

45 requests

43 requests

35requests

Stakeholder Meetings 108 30 62 48 56

FERC/State Commissions Dockets Pending

83 46 44 43 44

Legal Matters Pending 0 0 2 2 2

Executive Industry Activities 29 27 40 29 34

Number of Members 47 47 46 46 46

Withdrawal Notices 2 (2007) 4 (2006) 1 (2007)

5 (2006) 7 (2006) 7 (2006)

Staff 245 235 220 188 168

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SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT

4Q 2006

SPP FINANCIAL STATEMENTS 4TH QUARTER DISCUSSION

ALL DOLLAR VALUES IN THOUSANDS SPP preliminarily reports a net loss of $1,636 on revenues of $63,486 for FY’06 as compared to net income of $6,472 on revenues of $55,128 for FY’05. Gross revenues and net income exceed budget by $1,914 and $5,128, respectively. REVENUES Tariff administrative fees account for 72% of SPP’s total revenue stream as compared to 78% for FY’05. SPP’s administrative rate has remained at 16¢/MWh since January 2005. Administrative fee collections increased 7% from $42,758 in FY’05 to $45,831 in FY’06. This increase is due to expected internal load growth as well as the addition of Aquila and Sunflower transmission facilities to the SPP tariff. Billing units for FY’06 increased to 286,444,000 MWh from 267,238,000 MWh in FY’05. Gross transmission sales for FY’06 increased to $279,688 from $255,469 for FY’05. Aquila and Sunflower transmission facilities combine to account for $3,082 of this activity. The remainder of SPP’s revenues are categorized as follows:

FY’06 FY’05 Budget’06

Fees and Assessments $11,497 $9,295 $9,242

Contract Services 4,684 182 9,760

Miscellaneous Income 1,474 2,893 1,201

Fees and Assessments: The increase in FY’06 as compared to FY’05 and budget is the result of greater than expected collections under Schedule 12 of the tariff during all of FY’06. The variance reflects an increase in the Schedule 12 billing units (i.e. actual load). Contract Services: The contract with Entergy was not implemented in accordance with expectations resulting in actual revenues significantly behind the FY’06 budget estimate. However, the delay in implementation has also resulted in a corresponding reduction in expenses. Miscellaneous Income: The decline in FY’06 results from recognition of revenue related to numerous completed projects in FY’05.

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SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT

4Q 2006 EXPENSES Assessments and Fees, Personnel Expenses, and Outside Services represent 80% of SPP’s total expenses in FY’06 as compared to 77% for FY’05. Assessments and Fees are pass-through costs allocated to SPP in support of FERC and NERC operations; SPP management has no control over these expenditures. These totaled $10,386 in FY’06 as compared to $8,226 in FY’05. Personnel Expenses totaled $27,396 in FY’06 as compared to $18,150 for FY’05. Actual expenses are 5% below budget. Included in these expenses is the addition of 74 net staff (total staff as of December 31, 2006 was 242) and an increase in pension plan expense of $498 over the same period in FY’05. Outside Services expenditures provide for the support and operation of many of SPP’s specialized systems, most notably the commercial operations system which settles the Energy Imbalance Service (EIS) market. Throughout FY’06, SPP incurred $13,457 in outside services expenditures as compared to $9,983 in the prior year, and a budgeted amount of $11,021. The additional expenditures have enhanced SPP’s database administration capabilities and provided enhanced project management support for the EIS market project. At its May’06 meeting, the SPP Board of Directors approved additional funds to support EIS market development and implementation efforts. These expenditures were largely realized during 3Q’06. LIQUIDITY SPP’s liquidity has steadily declined over the past year as cash has been deployed to meet capital project requirements. Unrestricted cash balances were $12,517 as of December 31, 2006 as compared to $11,111 as of September 30, 2006 and $25,511 as of December 31, 2005. SPP generated $9,899 in cash from operations during FY’06 which, along with existing cash balances, was used to fund $18,904 in capital expenditures and $5,000 in principal payments on long-term debt. Existing cash and cash from operations will be sufficient to fund SPP’s needs through early FY’07 when additional financing is expected to fund completion of several ongoing capital projects as well as new initiatives. SPP maintains an $8,000 working capital facility with a commercial bank to fund any short-term cash shortfalls.

FYE’06 3Q’06 FYE’05

Unrestricted Cash $12,517 $11,111 $25,511

Current Ratio .78 .92 1.52

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SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT

4Q 2006 CAPITALIZATION SPP’s balance sheet is highly leveraged as a result of: 1) SPP’s policy to fund capital projects with debt financing, and 2) a rate setting process intended to fund only budgeted expenditures. Historical spending below budget has served to stabilize Member’s Equity and the debt/capitalization ratio.

FYE’06 3Q’06 FYE’05

Members’ Equity $12,131 $13,081 $13,767

Total Debt $35,000 $35,000 $40,000

Debt/Capital 74% 73% 74%

Total Liabilities/Members’ Equity 5.92 4.87 4.95

SPP anticipates new long-term financing to be issued in 1Q’07 related to its new operations facility currently under construction. Development of the EIS market as well as other project initiatives will also likely result in SPP entering the debt market during 1Q’07.

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Southwest Power PoolBalance Sheet

As of December 31, 2006

12/31/06 09/30/06 12/31/05($000)

ASSETS Current Assets Cash & Equivalents $12,517 $11,111 $25,511 Restricted Cash Deposits 15,698 14,714 16,541 Accounts Receivable (net) 5,682 7,101 5,660 Other Current Assets 2,657 2,560 2,910

----------------------- ----------------------- ----------------------- Total Current Assets 36,554 35,485 50,622 Total Fixed Assets 46,685 40,648 30,658 Total Other Assets 739 666 696

----------------------- ----------------------- -----------------------TOTAL ASSETS $83,978 $76,799 $81,976

============= ============= =============

LIABILITIES & EQUITY Liabilities Current Liabilities Accounts Payable (net) $4,140 $990 $283 Customer Deposits 15,698 14,714 16,541 Current Maturities of LT Debt 10,000 10,000 5,000 Other Current Liabilities 16,757 13,015 11,384

----------------------- ----------------------- ----------------------- Total Current Liabilites 46,595 38,718 33,208

----------------------- ----------------------- ----------------------- Long Term Liabilities 7.50% Senior Notes - 2008 5,000 5,000 10,000 4.78% Senior Notes - 2011 20,000 20,000 25,000 Other Long Term Liabilities 251

----------------------- ----------------------- ----------------------- Total Long Term Liabilities 25,251 25,000 35,000

----------------------- ----------------------- ----------------------- Net Income (1,636) (686) 6,472 Members' Equity 13,767 13,767 7,295

----------------------- ----------------------- ----------------------- Total Members' Equity 12,131 13,081 13,767

----------------------- ----------------------- -----------------------TOTAL LIABILITIES & EQUITY $83,978 $76,799 $81,976

============= ============= =============

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Southwest Power PoolIncome Statement

For the Twelve Months Ending December 31, 2006

Actual YTD Actual YTD Actual YTD Budget YTD2006 2005 Variance 2006 2006 Variance

($000)

Ordinary Income/Expense Income Tariff Administration Service $45,831 $42,758 $3,073 $45,831 $41,369 $4,462 Fees & Assessments 11,497 9,295 2,202 11,497 9,242 2,255 Contract Services Revenue 4,684 182 4,501 4,684 9,760 (5,076) Miscellaneous Income 1,474 2,893 (1,419) 1,474 1,201 273

-------------------- -------------------- ------------------- -------------------- -------------------- ------------------- Total Income 63,486 55,128 8,358 63,486 61,573 1,914

-------------------- -------------------- ------------------- -------------------- -------------------- ------------------- Expense Salary & Benefits 27,396 18,150 9,246 27,396 28,722 (1,326) Employee Travel 882 756 126 882 912 (29) Administrative 1,670 1,476 194 1,670 2,270 (600) Assessments & Fees 10,386 8,226 2,160 10,386 8,142 2,244 Meetings 398 395 3 398 445 (47) Communications 2,335 1,633 701 2,335 2,594 (260) Leases 777 740 37 777 808 (31) Maintenance 3,815 2,165 1,651 3,815 4,056 (241) Services 13,457 9,983 3,474 13,457 11,021 2,435 Regional State Committee 72 971 (899) 72 449 (376) Depreciation & Amortization 2,918 2,871 47 2,918 7,445 (4,527)

-------------------- -------------------- ------------------- -------------------- -------------------- ------------------- Total Expense 64,105 47,367 16,739 64,105 66,863 (2,758)

-------------------- -------------------- ------------------- -------------------- -------------------- -------------------Net Ordinary Income (619) 7,761 (8,381) (619) (5,291) 4,671

-------------------- -------------------- ------------------- -------------------- -------------------- -------------------Other Income/Expense Other Income Other Income 1 1 1 1 Interest Income 1,172 945 226 1,172 550 622

-------------------- -------------------- ------------------- -------------------- -------------------- ------------------- Total Other Income 1,173 945 227 1,173 550 623 Other Expense Interest Expense 2,191 2,383 (192) 2,191 2,023 168 Bad Debt Expense (2) (148) 146 (2) (2)

-------------------- -------------------- ------------------- -------------------- -------------------- ------------------- Total Other Expense 2,189 2,235 (46) 2,189 2,023 166

-------------------- -------------------- ------------------- -------------------- -------------------- -------------------Net Other Income (Expense) (1,017) (1,289) 273 (1,017) (1,473) 457

-------------------- -------------------- ------------------- -------------------- -------------------- -------------------Net Income (Loss) ($1,636) $6,472 ($8,108) ($1,636) ($6,764) $5,128

=========== =========== ========== =========== =========== ===========

23 of 101

Southwest Power PoolStatement of Cash Flows

For the Twelve Months Ending December 31, 2006

YTD ($000)

OPERATING ACTIVITIES Net income ($1,636) Adjustments to reconcile net income (loss) to new cash provided by operations: Depreciation 2,877 Amortization 41 Changes in assets and liabilities: Accounts receivable (22) Accrued revenue 337 Prepaid expenses (85) Accounts payable 3,858 Other current liabilities 5,373 Change in derivative liability 168 Customer deposits (843)

-----------------------Net cash provided by operating activities 10,067

INVESTING ACTIVITIES Purchase of property and equipment (18,904)

-----------------------Net cash used by investing activities (18,904)

FINANCING ACTIVITIES Repayment on 7.5% Senior Notes - 2008 (5,000)

-----------------------Net cash used by financing activities (5,000)

Net cash increase (decrease) for the period (13,837)

Cash at beginning of period 42,052-----------------------

Cash at end of period 28,215=============

24 of 101

SOUTHWEST POWER POOLCAPITAL EXPENDITURES

FOR THE TWELVE MONTHS ENDED DECEMBER 31, 2006

YTD YTD Variance(000's) Actuals Budget Fav/(Unfav)

Corporate Website Development 24 30 6 Current Facility Improvements 637 355 (282) Contract Services 377 401 24 Maintenance - Hardware 1,595 2,398 804 Maintenance - Software 687 1,079 392 Market Project 8,667 2,043 (6,624) New Facility 6,917 10,270 3,353 TOTAL CAPITAL EXPENDITURES 18,904 16,576 (2,328)

25 of 101

Southwest Power Pool2006 Foundation Actuals vs. Budget

For the Twelve Months Ending December 31, 2006

VarianceYTD 2006 YTD Budget Fav/(Unfav)

Revenues ($MM): Tariff Fees & Member Assessments 57,328 50,611 6,717 Other Member Services 1,474 1,201 273 Total Revenues 58,802 51,813 6,990

Operating Expenses ($MM): Salaries & Benefits 23,010 23,307 297 Other Operating Expenses 23,430 20,798 (2,632) Other Expense 4,024 4,578 554 Total Operating Expenses 50,464 48,682 (1,781)

Capital Expenditures 2,943 3,862 920

Notes• Tariff Fees & Member Assessments revenue are favorable to budget primarily due to an increase in

billable MW/h of 13% (includes FERC fees).• Personnel costs are favorable to budget as staffing timeline has trailed expectation. Increased pension

funding partially offset the favorable variance.• Other operating expenses are unfavorable to budget primarily due to an unexpected increase in FERC

fee accrual of $2.3MM. This amount is offset by Schedule 12 revenue.• Capex expenditures trail budget due to a reduction in computer hardware “refresh” activity.

26 of 101

Southwest Power Pool2006 Market Actuals vs. Budget

For the Twelve Months Ending December 31, 2006

Variance Approved Expected2000 - '05 YTD 2006 YTD Budget Fav/(Unfav) To Spend To Complete

Operating Expenses ($MM): Salaries & Benefits 917 1,062 145 1,654 737 Other Operating Expenses 14,825 9,148 8,162 (986) 24,352 379 Total Operating Expenses 10,065 9,224 (841) 26,006 1,117

Capital Expenditures 31,825 8,667 2,043 (6,624) 46,146 5,654

Notes

• “Approved To Spend” includes $7.1MM capital and $2MM operating expenses approved by SPP Board on May 17, 2006.• “Expected To Complete” includes $5.2MM in capital expenditures slated for 2007.• Operating expense is unfavorable to budget due to mid-year approvals without amending the budget.

27 of 101

Southwest Power Pool2006 Contract Services Actuals vs. Budget

For the Twelve Months Ending December 31, 2006

VarianceYTD 2006 YTD Budget Fav/(Unfav)

Revenues ($MM): Tariff Fees & Member Assessments 0 0 0 Contract Services 4,684 9,760 (5,076) Total Revenues 4,684 9,760 (5,076)

Operating Expenses ($MM): Salaries & Benefits 3,229 4,405 1,176 Other Operating Expenses 2,544 2,233 (311) Total Operating Expenses 5,773 6,638 865

Capital Expenditures 377 401 24

Notes

• All services for Entergy excluding weekly procurement were implemented November 17, 2006.• Implemented all services for LG&E on September 1, 2006.

28 of 101

Southwest Power Pool2006 SAS 70 Actuals vs. Budget

For the Twelve Months Ending December 31, 2006

VarianceYTD 2006 YTD Budget Fav/(Unfav)

Operating Expenses ($MM): Salaries & Benefits 240 328 89 Other Operating Expenses 664 441 (223) Total Operating Expenses 903 769 (134)

Notes• 2006 SAS70 type II audit excluded EIS market, but included readiness assessment of EIS market

controls.• The original 2006 budget was $400M. Audit expenditures approved by Finance Committee

on January 17, 2006 totaled $662M plus expenses.• Delay of EIS market (and elimination from audit scope) reduces expected audit fees to $607M

plus expenses.

29 of 101

Southwest Power Pool2006 New Facility Actuals vs. Budget

For the Twelve Months Ending December 31, 2006

Approved Expected2000 - '05 YTD 2006 YTD Budget Fav/(Unfav) To Spend To Complete

Operating Expenses ($MM): Salaries & Benefits 0 103 103 Other Operating Expenses 0 475 475 Total Operating Expenses 0 578 578

Capital Expenditures 344 6,917 10,270 3,353 11,902 4,641

Notes

• Operating expenses are favorable to budget since the building did not become operational in 2006.• "Expected to Complete" includes $1.6MM in new costs for '07 to furnish and bring the data center to full operation• Not to exceed construction price is 3% below approved budget and general construction is 94% complete. Completion

date is estimated as January 22, 2007.

30 of 101

SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT

4Q 2006

RELIABILITY COORDINATION

4Q06 v. 4Q05 shows an increase.

4Q06 v. 4Q05 shows an increase in MWh curtailed due to TLR.

TLR Events per Quarter

0

50

100

150

200

250

300

# of

Eve

nts

SPP 67 244 160 61 37 4Q-06 3Q-06 2Q-06 1Q-06 4Q-05

MWh Curtailed due to TLR

0

20000

40000

60000

80000

100000

120000

4Q-06 3Q-06 2Q-06 1Q-06 4Q-05

MW

h Firm Non-Firm

31 of 101

SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT

4Q 2006

SCHEDULING

4Q06 v. 4Q05 shows a slight decrease in the number of tags processed.

Daily Average Tags Processed

0

100

200

300

400

500

600

700

Num

ber o

f Tag

s

SPP 416 543 582 432 451 4Q-06 3Q-06 2Q-06 1Q-06 4Q-05

32 of 101

SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT

4Q 2006

TARIFF ADMINISTRATION

4Q06 v. 4Q05 shows a slight decrease in total transmission service requests.

Total Requests Submitted

0

10000

20000

30000

40000

50000

60000

SPP 36090 51695 48564 36567 37388 4Q-06 3Q-06 2Q-06 1Q-06 4Q-05

33 of 101

SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT

4Q 2006

4Q06 v. 4Q05 shows a slight decrease in percentage of transmission service requests confirmed.

% of Total Requests that are Confirmed

0%

10%

20%

30%

40%

50%

60%

70%

SPP 58% 47% 48% 56% 60% 4Q-06 3Q-06 2Q-06 1Q-06 4Q-05

34 of 101

SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT

4Q 2006

QUEUE STATUS REPORT Transmission Service Request Queue Number of study requests = 434, representing 31,037 MW Number of study requests for non-DC Tie = 282, representing 15,626 MW Number of DC Tie requests = 152, representing 15,411 MW - These requests cannot be processed due to impending DC Tie competition. During the same period last year Number of study requests for non-DC Tie = 72, representing 4,935 MW. Number of DC Tie requests = 102, representing 7,992 MW - These could not be processed due to impending DC Tie competition. Generation Interconnection Queue Number of active requests = 52, representing 14,119 MW • Number of wind requests = 34, representing 6,463 MW • Number of fossil fuel requests = 18, representing 7,656 MW Number of requests with Interconnection Agreement pending = 8 Interconnection Agreements signed during 2006 = 12 (Wind – 9 for 1146 MW; Fossil – 3 for 520 MW not included above) During the same period last year, there are 35 requests in process (22 wind; 13 fossil fuel) representing 6,340 MW (3,571 MW wind; 2,427 MW fossil fuel). There were 10 Interconnection Agreements pending.

35 of 101

SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT

4Q 2006

SPP Regulatory Affairs Activities

2006

The following is a brief summary of some of the activities undertaken by the SPP Regulatory Staff in 2006. A detailed report can be accessed at: SPP FERC/State Dockets

1. Reevaluation of FERC’s Annual Electric Assessment

On November 3, SPP submitted to the RLC for its consideration a White Paper regarding

the Federal Energy Regulatory Commission’s (“FERC” or “Commission”) current electric assessment methodology.

2. FERC Rulemaking Proceedings

a. Docket Nos. RM05-25 & RM05-17 - Order No. 888 Notice of Proposed Rulemaking (“NOPR”)

On May 19, 2006, the FERC issued a NOPR to update its proforma Open Access

Transmission Tariff and its decade old Order No. 888 (intended to prevent undue discrimination and preference in transmission service). SPP filed Initial and Reply Comments on its own as well as with the ISO/RTO Council (“IRC”).

FERC requested Supplemental Comments on the topics of redispatch service and conditional firm service, due December 15, 2006. SPP did not file Supplemental Comments.

b. Certification of the ERO and Procedures for the Establishment, Approval &

Enforcement of Electric Reliability Standards SPP has participated in the Electric Reliability Organization (“ERO”) certification

docket, RM05-30-000, individually and through the IRC. On November 29, 2006, in Docket No. RR07-6, the North American Electric Reliability Council (“NERC’) submitted a filing to FERC, which designates SPP as one of the regional entities.

c. FERC Docket No. RM06-4-000 - Promoting Transmission Investing through

Pricing Reform On December 22, 2006, FERC issued Order No. 679-A. d. Docket No. RM06-8-000 - Long-Term Firm Transmission Rights in Organized

Electric Markets

36 of 101

SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT

4Q 2006

FERC issued Order No. 681-A on November 16, 2006, denying rehearing and upholding

Order No. 681, while granting certain limited clarifications. Transmission organizations have until January 29, 2007, to file compliance proposals.

e. Docket Nos. RM06-16 and RM06-22 - Mandatory Reliability Standards for the

Bulk Power System NERC submitted 107 proposed reliability standards on April 4, 2006. FERC proposes

the approval of 83. It requested comments on another 20. The deadline for filing comments concerning the proposed reliability standards and the Notice of Proposed Rulemaking is January 3, 2007.

f. Docket RM07-3-000 Facilities Design, Connections and Maintenance Reliability

Standards The Commission opened this docket on November 27, 2006, for the purpose of

processing three new proposed reliability standards. Comments on staff’s preliminary assessment are due February 12, 2007.

g. Docket No. RM05-5 – NAESB Modifications to WEQ Business Practices

On November 16, NAESB filed modifications to its WEQ business practices for coordinate interchange. On December 15, the IRC filed comments regarding the modifications.

3. FERC Administrative Proceedings

a. FERC Federal-State Joint Boards on Security Constraints & Economic Dispatch On July 31, 2006, the Commission submitted a report in this docket to Congress.

4. FERC ERO Rules and Organizational Filings

a. NERC Filing of Version 5 Reliability Standards Development Procedure On April 4, 2006, the North American Electric Reliability Council (“NERC”) filed its

Reliability Standards Development Procedure in anticipation of its becoming the Electric Reliability Organization (“ERO”). On May 4, SPP filed in support of NERC’s ERO status.

b. NERC Filing of the 2007 Business Plans and Budgets NERC’s 2007 Business Plan and Budget and the 2007 Business Plan and Budgets of

Regional Entities were filed in Docket No. RR06-3-000 August 23, 2006. SPP intervened in this proceeding on September 29.

37 of 101

SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT

4Q 2006

5. FERC Electric Rate Filings of Interest

a. Docket No. ER06-451-000 - EIS Market Implementation SPP made 23 filings this year concerning implementation of our real-time energy

imbalance (“EIS”) market. In December, SPP made compliance filings intended to implement the market on February 1, 2007.

b. Docket No. ER06-729 - Attachment M Revisions

SPP filed a series of revisions to its loss replacement procedure. On November 20, 2006, SPP filed a limited request for rehearing of the Commission’s October 19, 2006 Order to allow it to settle “into and within” transactional losses at the imbalance price at the settlement location and to recognize losses from through and out transactions in the EIS market are indistinguishable from other energy obligations. On December 20, FERC granted SPP’s limited request for rehearing.

c. Docket Nos. ER03-765 & ER07-371 - Reactive Compensation

On September 26, FERC ordered SPP to file a revised Schedule 2 to provide reactive compensation for all generators. After several subsequent filings by SPP and others, SPP made its compliance filing on December 26. SPP requested an effective date of March 1, 2007. d. Docket No. ER06-1362 – Attachment X – Transmission Expansion Plan and

Credit Policy On December 28, FERC accepted SPP’s revisions to Attachment X.

e. Docket No. EL07-6 – FERC Inquiry Regarding Gas-Electric Coordination Issues

SPP must make a compliance filing either proposing changes to its scheduling to accommodate gas procurement for gas-fired generation or explaining why such changes are unnecessary. The filing must be made January 16, 2007. 7. Louisiana and New Mexico Appeal for Review of SPP RTO Orders (Case No. 04-

1398) – dismissed October 13, 2006.

FERC’s acceptance of SPP’s RTO proposal in Docket No. RT04-1-000 is now final.

8. Addressing First Three Waiver Requests under Attachment J SPP received requests for waiver under Attachment J of the SPP Tariff from Oklahoma Gas and Electric, Golden Spread Electric Cooperative and Westar Energy. SPP is evaluating these requests and developing additional procedures.

38 of 101

SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT

4Q 2006 9. Approval of Entergy’s ICT Proposal Entergy’s ICT Proposal is addressed in FERC Docket Nos. ER04-699-000 and ER05-1065-000, as well as Louisiana Public Service Commission Docket No. U-28155 and Arkansas Public Service Commission Docket No. 04-050-U. On October 18, FERC accepted Entergy’s May 24, 2006, compliance filing, directing that SPP be installed as the ICT within 30 days. Consequently, SPP began acting as the Independent Coordinator of Transmission for Entergy in mid-November. Rehearing of FERC’s September 22, 2006, Order was granted November 22 in Docket No. ER05-1065-003. 10. Arkansas Regulatory Proceedings

a. Docket No. 04-137-U

On August 10, 2006, the Arkansas Public Service Commission (“APSC”) awarded SPP a CCN to operate the transmission facilities of Southwestern Electric Power Company, Oklahoma Gas and Electric and Empire District Electric (“Empire”).

b. Docket Nos. 05-021-U, 06-077-U, 06-142-U

SPP filed in support of a number of applications for CCNs of member Transmission Owners to build transmission facilities. 11. Missouri Regulatory Proceedings

a. Docket Nos. EO-2006-0141 and EO-2006-0142

Empire District Electric Company and Kansas City Power & Light Company were granted authority to transfer functional control of their transmission assets to SPP. SPP filed in support. 12. Kansas Regulatory Proceeding

a. Docket No. 06-SPPE-202-COC

On September 19, 2006, SPP was awarded a CCN to manage and coordinate the use of certain transmission facilities in Kansas.

39 of 101

SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT

4Q 2006 13. Texas Regulatory Proceeding

a. Texas CREZ Rule – Project No. 31852

The Texas Public Service Commission instituted a rulemaking to address the designation of Competitive Renewable Energy Zones (“CREZ”) in Texas to support additional renewable energy and related transmission development. In December, the Commission finalized the rule and ERCOT filed a report containing several recommendations. SPP Regulatory Staff has been involved in the rulemaking process and will continue to be involved in the CREZ selection process in order to represent SPP’s unique position in Texas. 14. SPP EHV Overlay Assessment SPP Regulatory Staff also assisted in reporting on the SPP EHV Overlay Assessment. The study’s scope has been defined as providing a long range strategic assessment regarding the use of 345, 500, 765kV or higher transmission overlay within SPP and its potential integration with neighboring systems to address future needs. Formal assessment needs to begin this month and should conclude with a final report and recommendations in July of 2007.

40 of 101

SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT

4Q 2006

LEGAL MATTERS PENDING

No Legal Matters Pending Documents Processed in 2006: Vendor Contracts Reviewed by In-House Counsel: 318 OATT Form Service Agreements Processed: 106 Agreements requiring special processing and/or separate filing with FERC: 43 Digital Trust License Renewal Agreements Processed: 72 Mandatory Filings with State Governments and Financial Institutions: 58 ITO Transmission Service Agreements Processed: 24 Other Form Agreements Processed: 35 (Credit Agreements; Transmission Service Agreements, NDA’s etc.) TOTAL 656

41 of 101

SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT

4Q 2006

EXECUTIVE INDUSTRY ACTIVITIES

Executive Event Nick Brown ISO/RTO, St. Helena, CA (Oct. 3-4) Missouri Public Utility Alliance Conference, Lake Ozark, MO (Oct. 5) OATI, Las Vegas (Oct. 16-17) Transmission Access Policy Study Group, OKC (Nov. 6-7) Electric Power Research Institute Board Meeting, Albuquerque (Nov. 11-16) ISO/RTO, Washington D.C. (Dec. 5-6) NAESB, Houston, TX (Dec 13-14) Michael Desselle NERC Board of Trustees, Chattanooga, TN (Oct. 30 - Nov. 1) Transmission Access Policy Study Group, OKC (Nov. 6-7) NAESB Executive Committee Meeting, Dallas, TX (Nov. 14) NAESB WEQ Drafting Collaborative, Houston, TX (Nov. 28) Missouri Public Utility Alliance Board Meeting, Columbia, MO (Dec. 6) NAESB, Houston, TX (Dec 13-14) Les Dillahunty IRC Regulatory Legislative Committee, Dallas, TX (Oct. 12-14) La Tech University Mechanical Engineering Advisory Council, Ruston, LA

(Oct. 14) NARUC, South Beach, FL (Nov. 13-15) Kansas Electric Transmission Summit, Lawrence, KS (Nov. 28) Tom Dunn Missouri Public Utility Alliance Conference, Lake Ozark, MO (Oct. 5) Kansas Electric Transmission Summit, Lawrence, KS (Nov. 28) JP Morgan Chase, New York City (Dec. 6-7) Carl Monroe Harvard Business School, October 2006 Charles Yeung AEGIS Presentation on ERO, Henderson, NV (Oct. 18) NERC Regional Managers, St. Louis, MO (Oct. 26) NERC Stakeholders Committee, Chattanooga, TN (Oct. 31) T&D Summit, Albuquerque, NM (Nov. 6-7) ERAG Management Committee, Tampa, FL (Nov. 14) NERC Regional Managers, Houston, TX (Dec. 5-6) NERC Operating Committee, Houston, TX (Dec. 6-7) IRC/FERC Staff Meeting on NERC Standards, Wash. D.C. (Dec. 12)

42 of 101

SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT

4Q 2006

WITHDRAWAL LETTERS MEMBERS EFFECTIVE DATES Louisiana Energy & Power Authority 10/31/07 City of Lafayette Utilities System 10/31/07

43 of 101

SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT

4Q 2006

STAFFING REPORT

SPP Employee count as of January 1, 2006:

168

1Q New hires: 23 2Q New hires: 25 3Q New hires 34 4Q New hires 17 YTD Terminations:

2 – Retirees 14 – Voluntary terminations 0 – Involuntary terminations 6 – Interns (part time/seasonal)

22

SPP Employee count as of December 31, 2006

245

There are 295 full time employees in the 2007 budget.

44 of 101

Southwest Power Pool, Inc. FINANCE COMMITTEE

Report to the Board of Directors January 30, 2007

2007 SAS70 AUDIT PROGRAM

Organizational Roster The following persons are members or the Finance Committee:

Harry Skilton Larry Altenbaumer Gary Voigt Trudy Harper Kelly Harrison David Sartin

Director Director Arkansas Electric Cooperatives Corp. Tenaska Westar Energy American Electric Power

Background Annually, SPP engages an independent audit firm to perform an audit on SPP’s internal control environment consistent with Statement of Auditing Standards 70 (“SAS70”). SPP has previously engaged a type I SAS70 audit in 2005 which tested controls in place on a specific date. During 2006, SPP engaged a type II audit which tested the effectiveness of controls over a six month period. SPP engages these audits to assist its members and customers in meeting their individuals control documentation requirements.

Analysis SPP has engaged Price Waterhouse Coopers (“PwC”) to perform SAS70 audits in 2005 and 2006. PwC has met SPP’s expectations in its performance of these audits and brings to the audit an experienced team of auditors who have completed similar audits for SPP’s ISO/RTO peers.

The type II SAS70 audit requires a six month testing period. SPP believes a period beginning May 1, 2007 and ending October 31, 2007 is an appropriate period as it meets the testing period requirement, includes controls in place during EIS market operation (currently slated to be implemented February 1, 2007), and leaves a minimal “gap” period between the end of the audit test period and the end of SPP’s fiscal year.

This expenditure was included in SPP’s 2007 budget.

Recommendation Recommend to SPP’s Board of Directors the engagement of Price Waterhouse Coopers to perform a Type II SAS70 audit of SPP’s controls surrounding transmission and imbalance energy services.

Approved: Finance Committee December 11, 2006

Action Requested: Approve Recommendation

45 of 101

1

Strategic Planning Committee Report

Richard SpringChairman, Strategic Planning Committee

January 30, 2007

www.spp.org 2

Strategic Planning CommitteeReport to

SPP Board of Directorsand Members Committee

January 30, 2007Hilton Palacio Del Rio

San Antonio, TX

2

www.spp.org 3

Agenda

Organizational Effectiveness Initiatives

Strategic Plan Prioritization and Schedule

ERO/RE Cost Allocation (Action Item)

www.spp.org 4

Efforts to Improve Organizational Effectiveness

• Organizational Group Self-Assessments

• Organizational Group Surveys

• Chairs and Secretaries Meeting, November 9-10

3

www.spp.org 5

Organizational Group Survey Overview

• Survey was sent to six committees and twelve working groups

• Organizational group members were asked to rate four groups of attributes from 1-5:

Meeting PreparationMembershipMeeting ConductChair

• Each attribute group allowed for open-ended comments

www.spp.org 6

Brainstorming Session, Chairs and Secretaries, Nov. 9-10

• 40 specific ideas for improvement

• Ideas grouped into 5 categories:Meeting Management / Joint Meetings / Communications / Metrics

Governance / Consolidation / Restructuring / Process Flow

Nimbleness / Speed

External Relations

Compliance

4

www.spp.org 7

Strategic Planning Meeting – January 18, 2007

•Discussed each of the items developed at November meeting.

• Debated the appropriate committee to address1. Corporate Governance Committee – 102. Market Operation Policy Committee – 103. Corporate Compliance Committee – 24. Strategic Planning Committee – 25. SPP Staff - 16

www.spp.org 8

Strategic Plan Prioritization ResultsA B C Priority

ProductsSPP Regional Entity (RE) Transition 11 ATransmission Expansion/Economic Upgrades 6 4 ATransmission Expansion/Project Tracking 6 5 AMarket Development and Design 3 7 BBalancing Authority 1 8 B

ProcessesCommunication & Education 5 4 BCenter of Excellence 4 5 CContract Services 4 5 CMembership Development 1 7 C

A = Highest Priority; Immediate, requiring absolute attention; unbudgeted expenditures would be approved to accomplish objective

B = Important, but subserviant to Priority A; unbudgeted expenditures would not be authorized to accomplish objective

C = Ongoing objective; Important strategically to accomplish, but subserviant to A and B and hence a lower priority for scarce resources

5

www.spp.org 9

www.spp.org 10

6

www.spp.org 11

ERO/RE Cost Allocation (Action Required)

Recommendation:The Strategic Planning Committee recommends modifying the Delegation Agreement between NERC and SPP to change the allocation of ERO and RE costs from Balancing Areas in the SPP footprint to all the load serving entities in the SPP footprint.

Approved: Strategic Planning Committee - January 18, 2007Passed Unopposed

Action Requested:Approve recommendation and authorize Staff to take appropriate actions consistent with the recommendation.

Richard SpringChairman, Strategic Planning Committee [email protected]

Southwest Power Pool, Inc. STRATEGIC PLANNING COMMITTEE

Recommendation to the Board of Directors January 19, 2007

Regional Entity Funding

Organizational Roster The following persons are members of the Strategic Planning Committee:

Richard Spring, KCPL Mel Perkins, OGE Kevin Easley, GRDA Jim Eckelberger, Director Mike Palmer, EDE Joshua Martin, Director

Ricky Bittle, AECC Tom Grennan, KEPCO Tim Woolly, Xcel Energy Robert Janssen, Redbud Energy Harry Skilton, Director

Background In 2006, the Federal Energy Regulatory Commission (FERC) approved the North American Electric Reliability Corporation (NERC) to be the Electric Reliability Organization (ERO) responsible for the reliable operation of the U.S. interconnected bulk power system. The ERO may delegate regional compliance and reliability standards development responsibilities to a Regional Entity (RE). SPP has proposed to be a RE and the Board approved a comprehensive package of elements that formed the basis for SPP’s Delegation Agreement with NERC. That package included the estimated 2007 SPP RE budget and proposed allocation of such costs on a Balancing Authority basis within the SPP footprint.

FERC’s Order approving NERC as the ERO resulted in a change in the approach to funding reliability organizations. Specifically, NERC is now authorized to collect the costs associated with operating the ERO and the individual REs from all its jurisdictional loads, remitting funding to the REs in accordance with their approved budgets. In December 2006, NERC sent 1st quarter 2007 invoices for the assessment for Electric Reliability Organization (“ERO”) and Southwest Power Pool Regional Entity (“SPP”) dues. This change in approach became effective January 1, 2007.

Analysis During December, SPP was made aware of errors in the Net Energy for Load (NEL) values reported to NERC and has worked with its Balancing Areas to reconcile these errors. Additionally, some Balancing Areas expressed concern that they do not have arrangements to pass the NERC costs on to other Load Serving Entities within their Balancing Areas. Working with NERC, SPP obtained agreement from NERC to modify the Delegation Agreement to directly invoice those identified Load Serving Entities within SPP’s Balancing Areas subject to agreement from SPP.

To facilitate this modification, SPP staff contacted the BAs in its footprint to have them identify their respective 2005 NEL for themselves and the embedded loads in their Area along with the complete billing information for those loads. To gain the support of the Organization, the SPC considered a motion to modify the Delegation Agreement.

Recommendation The Strategic Planning Committee recommends modifying the Delegation Agreement between NERC and SPP to change the allocation of ERO and RE costs from Balancing Areas in the SPP footprint to all the load serving entities in the SPP footprint.

46 of 101

Approved: Strategic Planning Committee January 18, 2007

Passed Unopposed

Action Requested: Approve recommendation and authorize Staff to take appropriate actions consistent with the recommendation.

47 of 101

ID Task Name

1 SPP REGIONAL ENTITY IMPLEMENTATION PLAN2 Project Start

3 FERC Approval Schedule4 NERC RE Delegation Agreements Filed

5 NERC Reliability Standards Comments Due

6 RE Delegation Comments Due

7 FERC Order on NERC Reliability Stds (est)

8 FERC Order on RE Delegation Agreements

9 Operations of Regional Entity Begin

10

11 Governance12 Changes to Existing SPP Bylaws Proposed and Documented

13 Agenda Package Delivered

14 April 24th Board Meeting

15 Informal Trustee Search16 Develop Job Description and Requirements

17 Complete description/requirements document

18 Review and approval of document completed

19 Contact potential candidates

20 Issue formal offers

21 Selections complete (incl executed Code of Conduct Agreements)

22

23 SPP Employee Time Tracking24 Determine requirements for time tracking

25 Include requirements in SPP RE Budget

26 Spreadsheets completed

27 RE activities timetracking begins

28

29 Regional Standards Process30 Create document to depict changes to the present SPP criteria dev proc

31 Train SPP Staff secretaries, committee, working group and task force chairs

32 Update SPP website to accommodate notices for proposed standards/registration

33 SPP Staff Standards of Conduct documents executed

34

11/27

11/28

1/3

1/10

3/2

3/9

6/1

4/24

2/15

6/1

12/29

1/2

6/1

Oct Nov Dec Jan Feb Mar Apr May Jun Jul4Q06 1Q07 2Q07 3Q07

SPP Regional Entity Implementation Plan

Page 1 48 of 101

ID Task Name

35 SPP Compliance Program36 Changes to Compliance Program37 Whistleblower Pgm

38 Violations Hearing (replaces existing Reg Appeals process)

39 RE Trustees Review of Sanctions

40 Regional Comp Wkshop

41 SPP Compliance Changes communicated

42

43 Funding44 Proposal to SPP Board for Funding Modifications45 Update 2005 NEL figures

46 BAs submit NEL/LSE changes to SPP

47 Submit Data to NERC for invoicing

48 BOD approval of funding modifications & authorization to file at FERC

49 SPP Staff Coordinate filings with NERC

50 NERC issues revised 2nd qtr inv LSEs

51 NERC 2nd qtr invoices due

52

53 2008 Budget54 Begin 2008 Budget Research

55 Staff completes budget

56 Budget submitted to SPP Members Comm and Board for comments

57 Budget submitted to SPP RE Trustees for approval

58 Complete and approved budget submitted to NERC

1/30

3/30

5/11

6/22

6/29

Oct Nov Dec Jan Feb Mar Apr May Jun Jul4Q06 1Q07 2Q07 3Q07

SPP Regional Entity Implementation Plan

Page 2 49 of 101

IN THIS REPORT:

SPP Debuts the Org Report Org Group Chairs and Secretaries Hold Brainstorming Session EIS Market Launch Set for February 1 Market Working Group Approves PRRs at Monthly Meeting Operating Reliability Working Group Holds 4Q Meeting The Month in Review

SPP Debuts the Org Report

Welcome to the first installment of the Org Report, a monthly e-newsletter that summarizes and shares information about SPP’s organizational group activities. The Communications Department will work closely with the Staff Secretaries of each group to track key votes, decisions, and the development of initiatives.

We hope the Org Report will give you a better understanding of SPP and how our organizational groups impact and inform each other.

We will distribute the first few issues of this report via particular organizational groups’ Exploder lists. If you would like to continue receiving the Org Report after that time, please subscribe by visiting our Email List page (http://www.spp.org/exploder.asp) and selecting the Organizational Group E-Newsletter Exploder.

Org Group Chairs and Secretaries Hold Brainstorming Session

On November 9-10, SPP’s organizational group chairs and secretaries met to discuss ways to improve the effectiveness of our committees, working groups, and task forces. After reviewing survey results, Michael Desselle, Vice President of Process Integrity and CAO, led a brainstorming session to identify specific ideas for improvement.

The group came up with 40 ideas, which were arranged into 5 categories:

1. Meeting Management/Communications

2. Governance/Restructuring

3. Nimbleness/Speed

4. External Relations

5. Compliance

The Strategic Planning Committee (SPC) forwarded the results of the brainstorming session to the Board of Directors. The Board tasked the SPC with developing a plan to address and implement the recommendations identified during the organizational group chairs and secretaries meeting.

This is the first such meeting of SPP chairs and secretaries, and should lead to a more efficient and effective SPP.

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EIS Market Launch Set for February 1

At its December 12 meeting, the SPP Board of Directors authorized staff to file certification with the Federal Energy Regulatory Commission for a February 1, 2007, implementation of SPP's Energy Imbalance Services Market.

Read SPP’s Readiness Certification Filing

Market Working Group Approves PRRs at Monthly Meeting

The Market Working Group held its monthly meeting on December 5-6. Agenda items included: Protocol Revision Requests, Deployment Test Update, and System Stability Update.

The MWG approved the following: PRR 109 (Availability of LIP Data), PRR 114 (Protocol Revision Request), PRR 119 (Correction of Acronyms), PRR 121 (SPP Payments to Invoice Recipients), PRR 127 (A/S Plan Manual Changes), PRR 132 (Manual Status), PRR 133 (Definition of Scheduled Load), PRR 134 (Initial Settlement Timeline), and PRR 135 (Substitution of Missing Net Actual Interchange).

The MWG agreed to ask the MOPC, RTWG, and ORWG to review PRRs 132, 134 and 135 for the February 1st EIS Market Go Live.

Operating Reliability Working Group Holds 4Q Meeting

At their December 12 meeting, the ORWG reviewed and approved PRR110, PRR113, PRR114, PRR116, PRR117, PRR119, PRR120, PRR121, PRR125, PRR127, PRR132, PRR134, and PRR135.

The ORWG approved removing ramp rate restrictions in the Market Transition and Reversion Overview and suggested adding language in Section 6 indicating an ORWG-approved contingency reserve requirement increase during market transition.

Chair Scott Moore resigned from the ORWG as a result of workload changes at AEP. Pete Kuebeck will serve as Acting Chair until a permanent replacement can be named. Vacancies on the ORWG were filled by Dan Boezio of AEP and Danny McDaniel of CLECO.

The Month in Review

Business Practice Working Group, 12/13/06 and 12/21/06: The BPWG approved changes to Business Practice 2.11, a document that defines the criteria for requesting NITS service from non-designated resources. The BPWG requested that the RTWG, MOPC, and ORWG approve the document.

Compliance Committee, 12/11/2005: The Committee considered and provided direction to staff for the completion of the 2007 Contract for the External Market Monitor/Advisor. The contract became effective January 1, 2007.

Cost Allocation Working Group, 12/20/2006: The CAWG held a special meeting to review a draft recommendation to MOPC regarding the OGE waiver. The recommendation was approved.

Finance Committee, 12/11/2006: The committee met with external auditors to discuss results of 2006 SAS70 audit. Participants reviewed a recommendation to change financial security requirements of transmission customers requiring transmission system upgrades to provide service. They also reviewed the limitation of liability provisions in the SPP tariff and discussed reasons to consider changes to the provisions. Finally, the FC reviewed implications of PRR 134, which would change the initial settlement date for market transactions to 7 days following the operating day.

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Market Implementation Task Force, 12/01/06, 12/06/06, 12/08/06, 12/13/06, 12/18/06, and 12/20/06: The 12/1 and 12/8 meetings each included a Market Status Update and Deployment Test Debrief. Participants voted to accept the updated SPP Market Trials Approach. The group also drafted a Change Management Process and Guidelines to be presented to the Market Working Group. For a complete list of action items, visit the MITF Homepage and select the appropriate meeting materials from the Related Documents link at the left.

Market and Operations Policy Committee: MOPC approved PRR128 (Response to Notification of Market Infeasibility) and PRR125 (Violation Realization Limits), contingent on ORWG review. The group also discussed changing the compensation for reactive provision in Schedule 2 of the Tariff. This motion was defeated with several members providing minority opinions.

Operations Training Working Group, 12/11/2006: SPP staff will submit a draft pricing proposal for the 2007 Regional Training to the OTWG, post the 2007 Regional Training calendar, and continue planning for the April System Operator Conference.

Transmission Working Group, 12/11/2006: The TWG approved the 12/06/06 version of the SPP Transmission Expansion Plan 2006-2016 report, with recommended changes. SPP staff will update the Long Range Mitigation Review report and review the disposition of previously proposed Tariff Attachment O changes.

This is a summary of SPP organizational group meetings that occurred in December, 2006. For complete minutes of a particular group meeting, please visit www.spp.org and select that committee on the Committees and Groups page. Click on the “documents” folder in the left panel to view meeting minutes.

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1

Markets & OperationsPolicy Committee

• John Olsen – Vice Chair

2

www.spp.org 3

Action Items

www.spp.org 4

Overview – Action Items

• Tariff• Section 34• Market PRRs – PRRs 129, 132, 134 and 135• Attachment J and S

• Criteria• Update to Reflect NERC Standards – 7.1

• SPP Transmission Expansion Plan• STEP• Transmission Expansion• Base Plan Upgrades

• Waivers• OG&E• Westar

3

www.spp.org 5

Tariff Section 34 • Previously Section 34 accounted for the impact of Point-To-Point

revenue allocated to each zone on the calculation of the monthlydemand charge for network service by establishing a revenue credit associated with such revenue allocation.

• Modifications were needed to reflect circumstances where the posted revenue requirement includes a credit for allocated Point-To-Point revenue.

• Proposal is to credit the revenue allocation for the most recentcalendar year.

• Also, the modifications provide exemption from use of such credit if the revenue requirement is established using a formularate that is adjusted annually. Likewise, the proposed modifications provide exemption from use of such credit if the Point-To-Point revenue allocated to a zone is credited to the customers in the zone by some other mechanism.

www.spp.org 6

PRRs with Tariff Changes

• PRR129 - Provide for disputes of resettlement statements. In addition, specifies a deadline for resubmission of a returned Dispute.

• PRR132 - Additional changes, subsequent to PRR 120, to further clarify definitions of Start-up and Shut-down mode as well as provide additional clarity on the proper usage of Manual Status.

• PRR134 - Extends the initial settlement timeline line from 5 to 7 days.

• PRR135 - Add language to allow substitution of real time metering data when a Meter Agent fails to submit NAI meter data.

4

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IZCATF Recommendations

• At its meeting on January 4, 2007, the RTWG approved the following three-point recommendation:

1.The cost allocation for the inter-zonal portion of Base Plan Funding be changed from “Net Change MW-Mi” method to “Sum of Positive Impact MW-Mi” method and change all appropriate sections of the SPP OATT.

2.SPP use engineering and construction cost allocation share threshold of $100,000, below which there would be no allocation of costs.

3.CAWG give consideration to altering the existing allocation percentages and/or methods for Base Plan Funding to encourage the construction of EHV projects that have both economic and reliability benefits.

• RTWG approved modifications to Attachment J, Section III. A. 2. ii., to use positive MW-mile benefits and recommended $100,000 engineering and construction cost threshold and modifications to Attachment S, Section 4.1 to use “sum of the positive MW-Mi” impacts for the calculation.

• Tariff changes were approved by a vote of 6 in favor, 2 opposed (AEP and EDE) and 3 abstentions.

• DENNIS SLIDES

www.spp.org 8

Recommendation

• Section 34• The RTWG recommends that the MOPC approve the proposed

changes to Tariff Section 34.• MOPC approved with 2 abstentions (Xcel & KCPL)

• Tariff Languages for PRRs• The RTWG recommends that the MOPC approve these proposed

Tariff changes.• MOPC Approved Unanimously

• Attachment J and S• The RTWG recommends that the MOPC endorse the three-point

recommendation and approve the proposed modifications to Tariff Attachments J and S.

• MOPC approved with change to third recommendation point to delete “that have both economic and reliability benefits” No (EDE), 3 Abstentions (Tenaska, AEP, BPU)

• RSC approved the first two recommendations only.

5

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SPCWG Recommendation• NERC adopted revised Protection Reliability Standards in August 2006

• Standard PRC-002-1 — Define Regional Disturbance Monitoring and Reporting Requirements and

• Standard PRC-018-1 — Disturbance Monitoring Equipment Installation and Data Reporting

• Technical requirements are reflected in SPP criteria 7.1.• Current SPP criteria does not list the requirements for Dynamic

Disturbance Recorders (DDRs), a new requirement of NERC that will capture dynamic system events such as power swings at the selected locations and stored automatically for several days to be retrieved for system disturbances.

• Also, four DDR vendors participated in SPCWG meeting and confirmed that their products can meet proposed technical requirement.

• SPCWG unanimously agreed to recommend that the MOPC approve revision of Criteria 7.1 to reflect changes to satisfy new NERC standards PRC-002-01 and PRC-018-01.

• MOPC Approved

www.spp.org 10

2006 SPP Transmission Expansion Plan Scope

• Scope• developed by SPP Staff• Reviewed by Transmission Working Group at open meeting Nov. 9,

2005, Stakeholder recommended changes• Approved by TWG via email vote Dec. 19, 2005

• May 18, 2006 - Planning Summit Kansas City, Missouri• Over 100 people participated• Reviewed violations identified with analysis• Stakeholders requested to provide potential solutions

• August 16, 2006 - Planning WebEx - Public review of recommended Plans

• August 17 through August 23, 2006 - Stakeholder feedback on recommended plans

• November 15, 2006 - Public review of the report• December 11, 2006 - TWG approved the report• January 3, 2007 - Posted public version of TWG approved report

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Major Sections

• 176 pages• Executive Summary• Introduction and Scope of Analysis• Reliability

1. Load flow Analysis2. Stability Analysis3. Reactive Reserve Margin4. Recommendations

• Economic Screening of Projects• Three Appendices

www.spp.org 12

Executive Summary- All Transmission Projects 2006-2016

Project Cost by Project TypeTotal $1.4 billion

New Transformers14%

Transformer/Substation Upgrades

6%

New Caps/Reactors/Devices

4%

New Lines47%

Line Rebuilds/Upgrades29%

New Lines Line Rebuilds/Upgrades New Transformers Transformer/Substation Upgrades New Caps/Reactors/Devices

7

www.spp.org 13

What’s in STEP, Appendix A?

$1.4B

www.spp.org 14

What’s in STEP, Appendix B?

$203M

8

www.spp.org 15

What’s in Base Plan Upgrades?

$157M

www.spp.org 16

SPP Transmission Expansion Plan

$156M

$1M

$47M

9

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2006 STEPRecommendation #1

• Endorse the 2006-2016 SPP Transmission Expansion Plan for SPP Board of Directors approval.• Achieves requirements of Attachment O.• Assesses the reliability and economic operation of the

SPP Transmission System as required. • The TWG supports this recommendation.

• MOPC approved with “if a project sponsor steps forward” added at the beginning of the last paragraph on Page 140 of the plan.

www.spp.org 18

2006 STEPRecommendation #2

• Endorse the list of reliability projects in Appendix ‘B’• Supports SPP BOD approval to maintain reliability.• SPP BOD will authorize and direct the start of

construction. • The TWG supports this recommendation.

• MOPC approved with one Abstention (Redbud)

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www.spp.org 19

Base Plan Upgrades

• SPP OATT Definition 1.3h • Base Plan Upgrades: Those upgrades included in and

constructed pursuant to the SPP Transmission Expansion Plan in order to ensure the reliability of the Transmission System.

• Base Plan Upgrades shall also include those upgrades required for new or changed Designated Resources to the extent allowed for in Attachment J to this Tariff.

• SPP Review of STEP Projects• The SPP Staff independently evaluated reliability upgrades that

qualify for Base Plan Upgrade status as pursuant to the SPP OATT

1. STEP, Appendix B2. BPGTF Guidelines approved by MOPC 4/12/20063. Aggregate Study Base Plan Upgrades

www.spp.org 20

Base Plan Upgrades

• 53 Projects• 48 Projects from SPP Transmission Expansion Plan

(STEP), Appendix B• 5 Projects from Aggregate Study, Transmission Service

Requests (TSR)• $113M in total project costs

• $112M from STEP, Appendix B• $1M from TSR

• Open Stakeholder Review• Posted on www.spp.org – 12/12/06 –Regional Planning

Page• Committees Notified – MOPC, RSC, TWG, CAWG

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www.spp.org 21

Recommendation

• Staff requests endorsement of the proposed list of Base Plan Upgrades

• TWG endorsed Appendix B of the STEP• Endorsed 12/11/2006• Appendix B, minus existing facilities, is contained in the

Base Plan Upgrades list• Aggregate studies (TSR) Base Plan projects also included

in list for informational purposes• MOPC Approved

www.spp.org 22

Westar Waiver Request• OASIS Request 1086655 for new 20 year, 225 MW DNR at Spring Creek for

Westar NITS. Waiver requested Oct 13th in accordance with Section III.C.1 under SPP OATT Attachment J

• SPP recommending Rose Hill – Sooner 345 kV project to provide service, in lieu of 138 kV rebuilds of several flowgates between Northeast OK and Southeast KS

• regional and long term benefits of project,• increase in wholesale competition, and • need for project to accommodate Red Rock outlet

• Staff Recommendation - MOPC approve SPP staff recommendation to provide full Base Plan funding of Rose Hill – Sooner 345 kV project

• CAWG meeting January 24, 2007, recommends increase the Base Planfunding for the Westar waiver associated with reservation 1086655 be approved.

• MOPC Approved Staff Recommendation

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www.spp.org 23

OG&E Waiver Request

• CAWG recommends to the MOPC that the OG&E Reservation 1032973 designated as Centennial Wind Farm with a waiver amount recommended by the SPP staff of $747,000, be approved.

• CAWG specifically does not adopt the assumptions and analysis employed by SPP staff, however, the CAWG did confirm through its own review and analysis the reasonableness of the amount recommended by the SPP staff.

• MOPC Approved with One Abstention (KCP&L)

www.spp.org 24

Information Items

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Project Tracking – Strategic Effort

• Built/On ScheduleTransmission Owner (TO) correspondence agrees with 2006STEP reliability need date.

• Status Unknown“In Service” status is not confirmed by SPP Staff.Projected “In Service” date has not been provided to SPP Staff.

• DelayedTransmission Owner (TO) correspondence does not agree with 2006STEP reliability need date.

www.spp.org 26

Summary of Project Tracking

17 Projects$62M

5 Projects$7M

6 Projects$16M

6 Projects$30M

2008

44 Projects$73.5M

8 Projects$12.5M

21 Projects$19M

15 Projects$42M

2007

27 Projects$36.5M

19 Projects$21.5M

12 Projects$15M

2006

TotalDelayedStatus Unknown

Built/On Schedule

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www.spp.org 27

VRL are in four categories.1. Operational Constraints (Active on TLR - Flowgate loading

above the limit)• [$2,000]

2. Resource Ramp Rate (Active when resources are ramp rate constrained - Dispatch Instructions in excess of ramp rate)• [$5,000]

3. Market Balance (Generation to Load - Active when insufficient feasible capacity - Gap applied to NSI of insufficient BAs)• [$50,000]

4. Resource Capacity Maximum/Minimum (Active when all other categories are insufficient - Indication of need to shed load with no automated instructions to market)• [$100,000]

• MOPC Approved the VRLs currently in use in the software system subject to review within at least three months following energy market startup.

www.spp.org 28

MWG Post Go Live Discussions

• External Generation participation in EIS Market filing due to FERC 2 months after go-live

• Demand Response participation in EIS Market filing due to FERC 6 months after order

• MWG is to review Future Markets in the February meeting

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Transmission Operating Directives• The BPGTF determined that TODs shall be handled according to eight

agreement points:1.If a Transmission Operating Directive (TOD) is in place and a Transmission

Owner (TO) unilaterally withdraws the TOD before the TOD becomesineffective, any consequences (upgrades) lie with the TO.

2.SPP Staff (transmission planning and tariff administration) to determine when a TOD is ineffective.

3.“TOD Planning Effectiveness Standards” should be developed by SPP Staff and endorsed by the TWG and ORWG.

4.TOD must be on file with the SPP.5.If a TOD is “effective”, it will continue to be used in evaluation of TSRs.6.Upgrades associated with new TSRs associated with DRs that cause a TOD

to become ineffective will be classified as Base Plan Upgrades.7.TODs that are identified to be ineffective using the most current MDWG

base case models will not result in Base Plan Upgrades. 8.TODs that are identified to be ineffective using the transaction scenario

models based on the most current MDWG base case models (in the Transmission Expansion Planning Process) will result in Base Plan Upgrades.

www.spp.org 30

MOPC Action on TODs

• 2006 STEP looked to determine upgrades to fix problems associated with Transmission Operating Directives (TODs)

• < $6M due to ineffective TODs in horizon, 2006-2016. • $118M to replace all TOD’s in horizon, 2006-2016. • BPGTF recommendation for approval of eight agreement

points dealing with Transmission Operating Directives and Base Plan Upgrades

• MOPC passed unanimously with the exception of Agreement Point #7 and CAWG requested to review and comment on Agreement #7 and provide feedback to the MOPC prior to April 2007 meeting.

16

www.spp.org 31

Other MOPC Work

• Engineering Staff Reports • Supply Adequacy Audit• SPP EHV Overlay Study

• The UFLS report as recommended by the SPCWG was approved.

• Business Practice 2.11 failed to pass with a roll call vote of 46.4% against the recommendation. An MOPC conference call or e-mail vote will be needed after further work by RTWG and redefinition of the exception process by the BPWG.

Carl A. Monroe

[email protected]

Southwest Power Pool, Inc. MARKETS & OPERATIONS POLICY COMMITTEE

Recommendation to the Board of Directors January 30, 2007

Organizational Roster The following members represent the Regional Tariff Working Group:

AEP-West Arkansas Electric Cooperative Corp. Calpine Energy Services East Texas Electric Cooperative Empire District Electric Co. Kansas City Power & Light Kansas Electric Power Cooperative Lafayette Utilities System Midwest Energy Missouri Public Service Commission OG+E Electric Services Oklahoma Municipal Power Redbud Energy LP Southwest Power Pool Southwestern Public Service Co. Tenaska Power Services Co. Westar Energy Western Farmers Electric

Mr. Robert Pennybaker Mr. Ricky Bittle Mr. Jason Atwood Mr. David Brian Mr. Bary Warren Mr. Charles Locke Mr. Robert Bowser Mr. Ron Gary Mr. Bill Dowling Mr. Mike Proctor Mr. David Kays Mr. Gene Anderson Mr. Rob Janssen Mr. Pat Bourne Mr. Bernard Liu Mr. Mark Foreman Mr. Dennis Reed Mr. Mitchell Williams

The following stakeholders participated in group discussions:

AEP-West AEP-West AEP-West Arkansas Electric Cooperative Corp. Arkansas Electric Cooperative Corp. Arkansas Public Service Commission Calpine Energy Services East Texas Electric Cooperative Empire District Electric Co. Kansas City Power & Light Kansas Corporation Commission Kansas Corporation Commission Kansas Electric Power Cooperative Lafayette Utilities System Midwest Energy Missouri Public Service Commission

Mr. Dennis Bethel Mr. Robert Pennybaker Mr. Bob Tumilty Mr. Ricky Bittle Mr. Robert Shields Mr. Richard House Mr. Jason Atwood Mr. David Brian Mr. Bary Warren Mr. Charles Locke Mr. Larry Holloway Mr. Tom DeBaun Mr. Robert Bowser Mr. Ron Gary Mr. Bill Dowling Mr. Mike Proctor

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Missouri Public Service Commission Occidental Energy Ventures OG+E Electric Services Oklahoma Municipal Power Authority Southwestern Power Administration Southwest Power Pool Southwest Power Pool Southwest Power Pool Southwest Power Pool Southwestern Public Service Co. Southwestern Public Service Co. Southwestern Public Service Co. Tenaska Power Services Co. Tenaska Power Services Co. Westar Energy Westar Energy Western Farmers Electric Golden Spread Electric Coop.

Mr. Greg Meyer Mr. Tim Soles Mr. David Kays Mr. Gene Anderson Ms. Tracey Stewart Mr. Les Dillahunty Mr. Pat Bourne Mr. Mike Small Mr. John Mills Mr. Bernard Liu Mr. Tim Woolley Ms. Terri Eaton Ms. Ann Scott Mr. Mark Foreman Mr. Shah Hossain Mr. Dennis Reed Mr. Mitchell Williams Mr. Michael Wise

Tariff Section 34 Modifications Recommendation

Background The RTWG had previously proposed changes to Section 34 of the Tariff to account for the impact of Point-To-Point revenue allocated to each zone on the calculation of the monthly demand charge for network service by establishing a revenue credit associated with such revenue allocation. Upon further discussion, the RTWG determined that additional modifications were required.

Analysis The RTWG determined that it is necessary to modify the Tariff provisions to reflect circumstances where the posted revenue requirement includes a credit for allocated Point-To-Point revenue. Proposed modifications provide for the crediting of the revenue allocation for the most recent calendar year. Additionally, the proposed modifications provide exemption from use of such credit if the revenue requirement is established using a formula rate that is adjusted annually. Such formula rate mechanism automatically sets out a revenue requirement properly credited for the most recent calendar year Point-To-Point revenue allocation. Likewise, the proposed modifications provide exemption from use of such credit if the Point-To-Point revenue allocated to a zone is credited to the customers in its zone by some other mechanism.

At its meeting on January 4, 2007, the RTWG approved the proposed changes to Tariff Section 34 by a vote of nine in favor, one opposed and two abstentions. Xcel Energy opposed the change due to the fact that the Tariff revision does not conclusively deal with the situation they expect to face as a result of the settlement of their FERC transmission rate case. However, the Xcel case is still before FERC on rehearing and any special provisions required for the Xcel Energy zone can be established as part of a final compliance filing by SPP.

Recommendation The RTWG recommends that the MOPC approve the proposed changes to Tariff Section 34.

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Tariff Modifications for Protocol Revision Requests

Background The RTWG reviewed Tariff change recommendations made by the MWG associated with adoption of PRRs 129, 132, 134 and 135. Tariff change language, as approved by the RTWG, and RTWG voting information are set out on the PRR recommendation reports attached to the MWG recommendation.

Recommendation The RTWG recommends that the MOPC approve these proposed Tariff changes.

Inter-Zonal Cost Allocation – Unintended Consequences

Background The RTWG has undertaken a review of the inter-zonal cost allocation provisions of Tariff Attachments J and S in light of previously identified unintended consequences of the application of those provisions to specific base plan funded transmission expansion projects. The RTWG formed a task force to investigate alternative methods for the allocation of the 67% of revenue requirements to be allocated to pricing zones on the basis of benefit to such zones as a result of the construction of such upgrades.

Analysis At its meeting on January 4, 2007, the RTWG approved the following three-point recommendation:

1. The RTWG recommends that the methodology for determining the cost allocation for the inter-zonal portion of Base Plan funded transmission projects be changed from the “Net Change MW-Mi” method to the “Sum of Positive Impact MW-Mi” method and that these changes be reflected in all appropriate sections of the SPP OATT.

2. The RTWG recommends that SPP use engineering and construction cost allocation share threshold of $100,000, below which there would be no allocation of costs.

3. The RTWG recommends that the RSC Cost Allocation Working Group give further consideration to altering the existing regional/zonal allocation percentages and/or allocation methods for Base Plan projects to encourage the construction of high voltage projects that have both economic and reliability benefits.

In order to implement these recommendations the RTWG also approved Modification to Attachment J, Section III. A. 2. ii., to reflect the use of the positive MW-mile benefits and the recommended $100,000 engineering and construction cost threshold. It also approved modification to Attachment S, Section 4.1 to reflect the use of the “sum of the positive MW-mile impacts for the calculation.

The recommendation and Tariff changes were approved by a vote of six in favor, two opposed and three abstentions. AEP and Empire opposed the proposal. AEP expressed the concern that the $100,000 engineering and construction cost allocation threshold could result in avoidance of material cost allocation responsibility if many smaller projects were allocated using an exclusion threshold.

Empire provided the following written dissent.

The Empire District Electric Company (EDE) votes “no” on the RTWG recommendation to the MOPC. EDE believes that such a change “will not” avoid “unintended consequences” type results going forward. However, EDE does agree that the Sum of Positive MW-Mile method is superior to the Sum of the Net Change MW-Mile method.

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EDE believes that the RTWG did not go far enough in evaluating the cost allocation process for “unintended consequences”, therefore the MOPC should reject the Recommendation and direct the RTWG to provide a more comprehensive policy/tariff revision regarding the application of the project by project MW-Mile (flow based) allocation. Such revisions should include, but not be limited to:

i) revise the current project by project policy of a 1 time allocation to a policy that will re-evaluate the sum of positive mw-mile impacts/allocation at least every 2 years for significant changes;

ii) revise the current policy to reduce the complexity of using this MW-Mile method by “increasing” the E&C threshold from $100,000 to $10,000,000 (which would in effect allocate 67% of the cost of smaller projects to the host zone and no MW-Mile analysis/re-evaluation would be required).

iii) revise the current policy such that the calculated benefits for 1st tier non-SPP zones be allocated to the host/constructing zone rather than allocated to all calculated benefiting SPP zones.

iv) the inter-zonal cost allocation policy needs to “match up” with the future policy related to “economic upgrades”.

Recommendation The RTWG recommends that the MOPC endorse the three-point recommendation and approve the proposed modifications to Tariff Attachments J and S.

Approved: Regional Tariff Working Group January 4, 2007 Markets & Operations Committee January 16, 2007 (1) Changes to Tariff Section 34 Approved Approval with 2 Abstentions (Xcel, KCPL) (2) Tariff Language Changes for PRRs 129, 132, 124 and 135. Approved (3) Inter-Zonal Cost Allocation Endorsement Approved Approval with change to third recommendation point to delete “that have both economic and reliability benefits.” 1 No (Empire District), 3 Abstentions (Tenaska, AEP, Board of Public Utilities)

Action Requested: Approval of the proposed changes to Tariff Section 34, Tariff changes for PRRs, endorsement of the RTWG’s three-point recommendation regarding cost allocation method changes and approval of proposed changes to Tariff Attachments J and S.

Attachments: Attached are proposed changes to Tariff Section 34, Attachment J, Attachment S and PRRs 129, 132, 134 and 135.

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Modifications to Implement the RTWG Recommendations

Approved by the RTWG January 4, 2007

34 Rates and Charges

The Network Customer shall pay the Transmission Provider for any Direct Assignment

Facilities, Ancillary Services, Base Plan Charges (Schedule 11) and applicable study costs,

consistent with Commission policy, along with the following:

34.1 Monthly Demand Charge for all Zones except Zone 1: Except as provided in

Section 34.1a, for all network load served by the Transmission Provider, other

than network load physically located within Zone 1 the, American Electric Power

(Public Service Company of Oklahoma, Southwestern Electric Power Company,

and the SPP portion of Texas North Company, the Network Customer shall pay a

monthly Demand Charge, which shall be determined by multiplying its Load

Ratio Share times one twelfth (1/12) of the sum of the difference between,

Existing Zonal Annual Transmission Revenue Requirement specified in

Attachment H plus any credit for firm Point-to-Point revenue allocated to the

Zone under Attachment L included in such revenue requirement, minus less the

previous calendar year’s total firm Point-to-Point transmission revenue, that is not

otherwise shared or credited to its zonal customers under some other mechanism,

allocated to the Zone under Attachment L for each Zone in which the Network

Customer’s Network Load is physically located. Where a Network Customer has

designated Network Load not physically interconnected with the Transmission

System under Section 31.3, the Network Customer shall pay a monthly Demand

Charge, which shall be determined by multiplying its Load Ratio Share times one

twelfth (1/12) of the difference betweensum of the Existing Zonal Annual

Transmission Revenue Requirement specified in Attachment H minus plus any

credit for firm Point-to-Point revenue allocated to the Zone under Attachment L

included in such revenue requirement, less the previous calendar year’s total firm

Point-to-Point transmission revenue, that is not otherwise shared or credited to its

zonal customers under some other mechanism, allocated to the Zone under

Attachment L for the Zone that is the basis for charges under Schedule 9. In the

event the Existing Zonal Annual Transmission Revenue Requirement specified in

Attachment H for a specific Zone is established pursuant to a formula rate that is

adjusted annually, the Network Customer’s monthly Demand Charge shall be

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determined by multiplying the Network Customer’s Load Ratio Share times one

twelfth (1/12) of such revenue requirement.

34.1a Monthly Demand Charge – Zone 1: For all Network Load physically located

within Zone 1the American Electric Power (Public Service Company of

Oklahoma, Southwestern Electric Power Company, and the SPP portion of Texas

North Company), the Network Customer shall pay a monthly Demand Charge

calculated as shown on Addendum 1 to Attachment H.

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Modifications to Implement the RTWG Cost Allocation Recommendations

Approved by the RTWG January 4, 2007

ATTACHMENT J (Partial)

Recovery Of Costs Associated With New Facilities I. Direct Assignment Facilities

Where a System Impact and/or Facilities Study indicates the need to construct Direct

Assignment Facilities to accommodate a request for Transmission Service, the Transmission

Customer shall be charged the full cost of such Direct Assignment Facilities. Such costs shall be

specified in a Service Agreement.

II. Network Upgrades

There shall be four types of Network Upgrades: Base Plan Upgrades, Economic

Upgrades, Requested Upgrades, and generation interconnection related Network Upgrades as

defined in Attachment V to this Tariff. The costs of completed Network Upgrades shall be

allocated as specified in Sections III through VI of this Attachment.

III. Base Plan Upgrades

A single Base Plan Upgrade is comprised of any upgrade or group of upgrades required

to be made to a single transmission circuit, where a transmission circuit is comprised of all

elements load carrying between circuit breakers or the comparable switching devices.

A. Allocation of Base Plan Upgrade Costs

1. If the cost of a Base Plan Upgrade is less than or equal to $100,000, the

annual transmission revenue requirement associated with such Base Plan

Upgrade shall be allocated to the Base Plan Zonal Annual Transmission

Revenue Requirement of the Zone in which the Base Plan Upgrade is

located.

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2. If the cost of a Base Plan Upgrade is greater than $100,000, then:

i. X% of the annual transmission revenue requirement associated

with such Base Plan Upgrade shall be allocated to the Base Plan

Region-wide Annual Transmission Revenue Requirement and

recovered through the Base Plan Region-wide Charge. The initial

value of X shall be 33%.

ii. (100-X)% of the annual transmission revenue requirement

associated with such Base Plan Upgrade shall be allocated to the

Base Plan Zonal Annual Transmission Revenue Requirement and

recovered through the Base Plan Zonal Charge. This portion of the

annual transmission revenue requirement for each Base Plan

Upgrade shall be allocated to the Base Plan Zonal Annual

Transmission Revenue Requirement of specific Zones based on the

Zones’ share of the incremental positive MW-mile benefits as

computed in Section 4 of Attachment S to this Tariff. Each Zone

with a benefit of at least 10 MW-miles from a given Base Plan

Upgrade shall be allocated a portion of the Base Plan Zonal

Annual Transmission Revenue Requirement for such upgrade

based on its incremental positive MW-mile benefit divided by the

sum of the incremental positive MW-mile benefits for all of those

Zones with a benefit of at least 10 MW-miles from the upgrade,

provided that such allocation represents an engineering and

construction cost of at least $100,000.

B. Conditions for Classifying Upgrades Associated with Designated Resources

As Base Plan Upgrades

If the cost of any Network Upgrade or group of Network Upgrades to a

single transmission circuit associated with a new or changed Designated Resource

is less than or equal to $100,000: (i) such upgrade(s) shall be classified as a Base

Plan Upgrade; and (ii) the annual transmission revenue requirement associated

with such upgrade(s) shall be allocated in accordance with Section III.A.1.

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Modifications to Implement the RTWG Cost Allocation Recommendations

Approved by the RTWG January 4, 2007

ATTACHMENT S – (Partial) Procedure for Calculation of MW-Mile Impacts for Use in Assignment of Revenue

Requirements, Revenue Allocation and Determination of Losses

3.3 Application to Determination of Losses - Transmission service MW-mile impacts

using this MW-mile methodology shall be set forth in matrices developed by SPP

and posted on SPP OASIS. The matrices shall be changed twice per year. The

Summer season shall consist of the months of June through September inclusive.

The Winter season shall consist of the months of October through May inclusive.

3.4 Generator and Load Dispatch - All capacity transactions are simulated as coming

from all of a seller's on-line generation, except for that generation which is

already fully loaded, in proportion to unit MVA base (nameplate rating). The

transaction is simulated as delivered to all of the buyer's load.

Energy transactions are simulated as coming from all of the seller's on-line generation,

except for that generation which is already fully loaded, in proportion to the unit MVA base

(nameplate rating) and delivered to all of the buyer's load.

Each load on a bus at which the buyer represents load ownership will be allocated a

proportionate amount of the transaction. The portion of the transaction allocated to at any given

bus is the amount of load owned by the buyer on that bus divided by the total load owned by the

buyer.

4. Calculating the Impact for Base Plan Zonal Annual Transmission Revenue

Requirement Assignment

The zonal portion of the revenue requirements associated with Base Plan Upgrades shall

be assigned to Zones using the Incremental MW-mile Benefit Determination. SPP shall develop

a summer season model of the Transmission System, as specified in this Attachment S, using the

most recent information available, that includes all of the transmission enhancements included in

the approved SPP Transmission Expansion Plan. For this benefit determination, a comparison is

made between this model with all upgrades in service and with each approved upgrade removed.

The difference in MW-mile impacts for each Zone provides the information necessary for the

determination of the magnitude of benefit for each Zone.

4.1 Explanation of the Incremental MW-mile Benefit Determination Calculation –

The incremental MW-mile is determined by building the base case with all Base

Plan Upgrades in service. A MW-mile calculation is performed by measuring the

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flows on each line multiplied by the distance as described in Section 3.2. The net

changesum of the positive MW-mile impacts is used for this calculation. Then a

benefit determination calculation is made with each new transmission upgrade

removed individually. The reduction in MW-mile impact due to each new

transmission upgrade is the measure of its zonal benefit.

4.2 The results of this MW-mile analysis shall be posted on the SPP website.

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PRR Number 129 PRR

Title Dispute Process for Resettlement Statements

Timeline (Normal or Urgent)

Urgent Recommended Action Approve

Protocol Section(s) Requiring Revision (include Section No., Title and Version)

Section 11.9

Revision Description Provide for disputes of resettlement statements. In addition, specifies a deadline for resubmission of a returned Dispute.

PRR Recommendation (indicate whether all segments were present for the vote, and the segment of parties that voted no or abstained)

Protocol Language: Unanimously approved in the December 21, 2006 MWG conference call.

RTWG Review The vote was 10 in favor, one opposed and two abstentions. The AEP RTWG representative was not comfortable with the RTWG substituting its judgment for that of the MWG.

ORWG Review Approved at the November 29, 2006 ORWG Meeting.

MOPC Recommendation (indicate whether all segments were present for the vote, and the segment of parties that voted no or abstained)

Original Sponsor Name Terri Eaton Company Xcel Energy

Comments Received Comment Author Comment Description

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Proposed Protocol Language Revision

11.9 Disputes A Market Participant may dispute items set forth in any settlement statement (Initial, Final, or Resettlement) its Initial or Final Statements. A Market Participant may only dispute items set forth in a Resettlement Statement through the External Arbitration procedures of the SPP OATT. . The dispute must be filed on the Portal using the Contents of Notice dispute form. See Attachment AE Section 6.3(a) of SPP OATT for minimum content of a notice of dispute.

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11.9.1 Dispute Submission Timeline A Market Participant may dispute settlement of any Operating Day as soon as the Initial Settlement Statement for that Operating Day is issued, and up to 90 Businesscalendar Ddays after the Final Settlement Statement for that Operating Day is issued. In the case of Resettlement Statements, a Market Participant may only dispute incremental incremental changes in settlement data for an Operating Day that occur between issuance of the Final Settlement Statement and the first Resettlement Statement or between issuance of Resettlement Statements. A dispute relating to a Resettlement Statement must be filed within 14 Businesscalendar Ddays of issuance of the Resettlement Statement.

The Market Participant may file the dispute as early as the Initial Settlement Statement has been made available, but no later than 90 calendar days after the Invoice containing the Final Settlement Statement that contains the disputed data.

In the event that on the 89th calendar day the Portal is unavailable on the day prior to the deadline for submission of a dispute, due to technical or other reasons, SPP shall extend the dispute submittal deadline by the number of Business Days equal to the sequential number of Business Days on which the Portal was unavailableby a minimum of one working day.

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Additional days will be appropriately added if the Portal is unavailable for two or more sequential days.

11.9.2 SPP Dispute Processing SPP shall determine if the dispute is accepted by verifying that the dispute was submitted within the specified time and contains at least the minimum required information as described in Attachment AE of the SPP OATT. SPP shall make reasonable attempts to remedy any informational deficiencies by working with the Market Participant(s). Contents of Notice will be rejected if SPP determines required information is missing. The Dispute will be returned to the Market Participant with an explanation of the missing data no later than thirty days after the receipt of the original or resubmitted dispute. A Market Participant will be able to resubmit the dispute with additional information within 20 Business Days after the Dispute is returned to the Market Participant unless SPP grants an extension of this deadline for good cause. Once the Market Participant sends all required information and SPP determines the settlement and billing dispute is timely and complete, the dispute status will be considered “Open”. SPP will issue a settlement and billing dispute resolution report containing information related to the disposition of the dispute. SPP will make all reasonable attempts to resolve all “Open” disputes relating to all Settlement Statements within 30 calendar days after the settlement and billing dispute due date as specified in the Settlement Calendar. SPP will post the necessary adjustments for resolved settlement and billing disputes on the next Resettlement, or Final Settlement process. For settlement and billing disputes requiring complex research or additional time for resolution, and late disputes that can be reasonably processed, SPP will notify the Market Participant of the length of time expected to research and post those disputes through research and, if a portion or all of the dispute is granted, SPP will post the necessary adjustments on the next available Settlement Statement for the Operating Day, if any portion or all of the dispute is Granted. Statement or Invoice Recipients have the right to proceed to the External Arbitration process in Dispute Resolution of the Tariff for timely filed disputes that cannot be resolved through the settlement and billing dispute process.

Tariff Language:

Invoice Disputes In the event that a dispute arises between the Market Participant and the Transmission Provider concerning any initial, or final, or rResettlement settlement statements contained within an invoice that cannot be resolved to the Market Participant’s satisfaction, such disputes shall be resolved as follows: a) In the case of a dispute relating to an initial or final settlement statement, the Market Participant must notify the Transmission Provider within 90 Calendar Days following the issue

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date of the applicable invoice of the items that the Market Participant wishes to dispute. In the case of Resesettlement statements, the Market Participant must notify the Transmission Provider within 3014 Calendar Days following the issue date of the applicable invoice of the items contained in that statement that the Market Participant wishes to dispute, which issues must relate to incremental changes in data that occurred between issuance of the final settlement statement and the first Rresettlement statement or between Rresettlement statements.

The Market Participant must notify the Transmission Provider within 30 Calendar Days following the issue date of the applicable invoice that contains the final settlement statement with items that the Market Participant wishes to dispute. TThe notice of dispute must contain the following minimum information specified in the Market Protocols. :

• Statement type (iInitial, fFinal, rResettlement 1-11, ad hoc resettlement) • Charge type • Estimated dispute amount in dollars • Operating Day • Start interval • End interval • Statement ID • Transmission Customer • Settlement Location • Long description • Short description .

No items associated with a final settlement statement contained within an invoice may be disputed after 90 Calendar Days following the issuance of the invoice except as specified under subsection 6.3(b).

6.3 c) The Transmission Provider shall use its best efforts to notify the Market Participant of approval or denial of the submitted notice of dispute within 20 Business Days following the close of the applicable 30 90 day or 30 day window specified under subsection 6.3(a) or subsection 6.3(b). If the transmission Provider estimates it will take longer than the 20 Business Day window to analyze a specific billing dispute, the Transmission Provider shall notify the Market Participant and provide an estimate of the amount of time required to complete the analysis.

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PRR Number 132 PRR

Title Manual Status

Timeline (Normal or Urgent)

Urgent Recommended Action Approve

Protocol Section(s) Requiring Revision (include Section No., Title and Version)

Section 3.2 and Glossary

Revision Description

Correct definition of manual status that was approved in PRR 120.There was a joint meeting on September 14, 2006 between the MWG and MITF that provided the correct language. Additional changes, subsequent to PRR 120, to further clarify definitions of Start-up and Shut-down mode as well as provide additional clarity on the proper usage of Manual Status.

PRR Recommendation (indicate whether all segments were present for the vote, and the segment of parties that voted no or abstained)

Approved in the December 5-6, 2006 MWG meeting with 1 abstention (Xcel).

RTWG Review RTWG vote was 12 in favor, none opposed and 3 abstentions at the January 4, 2007 meeting.

ORWG Review Approved at the December 12, 2006 ORWG meeting.

MOPC Recommendation (indicate whether all segments were present for the vote, and the segment of parties that voted no or abstained)

Original Sponsor Name Emily Davis Company Southwest Power Pool

Comments Received Comment Author Comment Description

Terri Eaton Added language that further explained the use/restriction on Manual Status

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Proposed Protocol Language Revision

3.2 Manual—a unit Resource that is (a) Not capable of following SPP-provided dDispatch setpointsInstructions, either by virtue of: (1) being an intermittent Intermittent in natureResource; or (2) undergoing a Resource Ttesting, starupStartup, or shutdown Shutdown sequenceMode; and (b) Not capable of adhering to a self-providing a schedule Schedule in advance of SPP scheduling deadlines, either by virtue of: (1) being an intermittent Intermittent in natureResource; or (2) undergoing operating in Resource a tTesting, starupStartup, or shutdown Shutdown sequence Mode where the inception, termination, or duration of the testing, startStart-up or shutShut-down process cannot be confirmed or predicted. cannot be confirmed beforehand such that the unit output during the sequence cannot be predicted with precision Units Resources in manual status will be permitted to report ancillary Ancillary services Services if the limitations on their ability to follow setpoints Dispatch Instructions or report a predeterminedadhere to their schedule Schedules do not preclude them from providing said ancillary Ancillary servicesServices.

Glossary

Start-up Mode

A period of time before the Resource reaches its Minimum Capacity Operating Limit as indicated in the Resource Plan, but not to exceed 2 hours before and after the scheduled time for a unit Resource to synchronize to the grid, during which a Resource will be exempt from Uninstructed Deviation Penalties.

Shut-down Mode

A period of time after the Resource operates below its Minimum Capacity Operating Limit as indicated in the Resource Plan, but not to exceed one hour before and after the scheduled time for a unit Resource to be removed from the electrical grid, during which a Resource will be exempt from Uninstructed Deviation Penalties.

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Tariff Language:

Change the definitions of the two above items.

The RTWG made the following observations:

1. Revise definition of Shut-Down Mode and Start-Up Mode 1.1.38 and 1.1.37

2. The RTWG was concerned that there may be other places in the Tariff language that are impacted by the definition change or the clarification desired. They asked for consultant review of the Tariff for any changes needed prior to the MOPC meeting.

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PRR Number 134 PRR

Title Initial Settlement Timeline

Timeline (Normal or Urgent)

Urgent Recommended Action Approve

Protocol Section(s) Requiring Revision (include Section No., Title and Version)

Section 11.6.1 and 11.6.4

Revision Description

Currently, the initial settlement statement is run immediately after the due date for meter data submissions. This allows no time to investigate missing and incomplete meter data and pursue corrective action with the meter agents prior to posting initial statments. Extending the timeline for initial settlement to seven days affords the opportunity to obtain the missing or corrected meter data needed to produce more accurate settlement statements. This issue was discussed with the Credit Task Force on November 30. The Credit Task Force unanimously passed a motion to support this change. Errors/omissions in the meter data can lead to significant RNU costs for all MPs. This may impact the credit requirements of MPs as it will expand the credit exposure but the overall security requirement should be reduced because of reduction in RNU.

PRR Recommendation (indicate whether all segments were present for the vote, and the segment of parties that voted no or abstained)

Approved in the December 5-6, 2006 MWG meeting with one abstention (Westar).

RTWG Review The RTWG vote was 12 in favor, none opposed and one abstention at the January 4, 2007 meeting.

ORWG Review No reliability implications at the December 12, 2006 ORWG meeting.

MOPC Recommendation (indicate whether all segments were present for the vote, and the segment of parties that voted no or abstained)

Original Sponsor Name SDMSTF Company

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Comments Received Comment Author Comment Description

Proposed Protocol Language Revision

11.6.1 Initial Settlement Statements SPP will use settlement data to produce the initial statements for each Market Participant for the given Operating Day. Initial statements will be created at the end of the fifth seventh (5th7th) calendar day following the Operating Day. If the fifth seventh (5th7th) day is not a Business Day, the initial statement is issued on the next Business Day thereafter.

11.6.4 Settlement Timeline SPP shall create Settlement Statements daily for each Market Participant, detailing each Market Participants cost responsibility. Settlement Statements are published through the Portal on each business day. SPP shall prepare an invoice each billing cycle for each Market Participant showing the net amount to be paid or received by the Market Participant. In order to issue a settlement statement, SPP may use estimated, disputed or calculated meter data and schedule information. Settlement Statements shall provide sufficient detail to allow verification of the billing amounts and completion of the Market Participant’s internal accounting.

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Settlements Timeline

ISS-Initial Settlement Statement FSS-Final Settlement Statement

Sunday Monday Tuesday Wednesday Thursday Friday Saturday

Day 1 Day2 Day 3 Day 4 Day 5 Day 6 Day 7 Day 8 Day 9 Day 10 Day 11 Day 12 Day 13

ISS Day 1

ISS Day 2

ISS Day 3

ISS Day 4

ISS Day 5

Day 14 Day 15 Day 16 Day 17 Day 18 Day 19 Day 20

ISS Day 6 ISS Day 7 ISS Day 8

ISS Day 9

ISS Day 10

ISS Day 11

ISS Day 12

Time Lapse for Day 21 to Day 48

Day 49 Day 50 Day 51 Day 52 Day 53 Day 54 Day 55

ISS Day 41 ISS Day 42 ISS Day 43 FSS Day 3 FSS Day 4 FSS Day 5

ISS Day 44 FSS Day 6

ISS Day 45 FSS Day 7

ISS Day 46 FSS Day 8

ISS Day 47 FSS Day 9

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Tariff Language:

Section 6.1 (a) of Attachment AE: (a) The Transmission Provider shall issue a preliminary settlement statement for an Operating Day no later than 5 7 Calendar Days following the applicable Operating Day unless the 5th 7th day following the applicable Operating Day is not a Business Day, in which case, the preliminary settlement statement shall be issued on the first Business Day thereafter.

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PRR Number 135 PRR

Title Substitution of Missing Net Actual Interchange

Timeline (Normal or Urgent)

Urgent Recommended Action Approve

Protocol Section(s) Requiring Revision (include Section No., Title and Version)

Append to Appendix E as a new Section 7.3.5

Revision Description Add language to allow substitution of real time metering data when a Balancing AuthorityMeter Agent fails to submit NAI (Net Area Actual Interchange) meter data.

PRR Recommendation (indicate whether all segments were present for the vote, and the segment of parties that voted no or abstained)

Approved in the December 5-6, 2006 MWG meeting with 1 no vote (OMPA) and 1 abstention (Westar).

RTWG Review RTWG vote was 12 in favor, none opposed and 2 abstentions at the January 4, 2007 meeting.

ORWG Review No reliability implications at the December 12, 2006 ORWG meeting.

MOPC Recommendation (indicate whether all segments were present for the vote, and the segment of parties that voted no or abstained)

Original Sponsor Name SDMSTF Company

Comments Received Comment Author Comment Description

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Proposed Protocol Language Revision

Append the following language to Appendix E

New Section 7.3.5 Substitution of NSI for missing NAI Metering Data Net Scheduled Interchange (NSI) will be substituted for Net Area Interchange in the event that a Balancing Authority fails to submit Net Area Interchange metering data. In the event that a Meter Agent fails to submit Net Actual Interchange metering data, SPP will substitute the hourly integrated Net Scheduled Interchange (NSI) for Net Actual Interchange.

Tariff Language: 6.1 (d)

(d) To the extent that a Market Participant, or its designated meter agent, does not submit meter data representing that Market Participant's actual hourly Resource output and load consumption in accordance with the timelines specified in the Market Protocols, the Transmission Provider shall use estimated data for that Market Participant that is equal to that Market Participant's Scheduled Generation and Scheduled Load for the applicable hours for the purposes of calculating the preliminary statements specified under Sections 6.1 (a). To the extent a Meter Agent does not submit data representing the Net Actual Interchange, the Transmission Provider will substitute hourly integrated Adjusted Net Scheduled Interchange. In the event that actual meter data is not submitted prior to the issuance of a final settlement statement, the Transmission Provider shall use the best available data to it, which may include estimated meter data as developed by the Transmission Provider, for the purposes of calculating final settlement statement.

Net Actual Interchange

The algebraic sum of all energy flowing into or out of a Settlement Area during a Settlement Interval.

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Southwest Power Pool, Inc.

MARKETS & OPERATIONS POLICY COMMITTEE

Recommendation to the Board of Directors

January 30, 2007

Organizational Roster The following members represent the System Protection Working Group: Fred Ipock, Chairman Heidt Melson Maurice Robinson Bob Roach Dean Sikes Doug Jackson Shawn Jacobs Lynn Schroeder Mak Nagle, Secretary

City Utilities of Springfield, Missouri Xcel Energy Arkansas Electric Cooperative Corporation Kansas City Power & Light. Cleco American Electric Power OG+E Electric Services Westar Energy Southwest Power Pool

Background NERC Board of Trustees adopted the revised version of Protection Reliability Standards in August 2006 Standard PRC-002-1 — Define Regional Disturbance Monitoring and Reporting Requirements and Standard PRC-018-1 — Disturbance Monitoring Equipment Installation and Data Reporting The technical requirements as listed in these NERC’s standards are reflected in SPP criteria 7.1. SPCWG reviewed the latest technical requirements that were made in the NERC criterion and correspondingly suggested recommending changes in SPP criteria 7.1. The current version of SPP criteria does not list the technical requirements for Dynamic Disturbance Recorders (DDRs), a new requirement that NERC is recommending through their PRC standards that will capture dynamic system events such as power swings at the selected locations. This data is stored automatically for several days and can be retrieved if necessary in the event of system disturbance. SPCWG unanimously agreed to add the technical requirements as listed for the Dynamic Disturbance Recorders in the SPP criteria. The SPCWG believes that these technical requirements are reasonable for the proposed DDRs. Also, four DDR vendors participated in SPCWG meeting and confirmed that their product can meet proposed technical requirement as listed in NERC PRC standards as well as SPP criteria 7.1. Recommendation

Recommend that the MOPC approve revision of Criteria 7.1 to reflect changes to satisfy new NERC standards PRC-002-01 and PRC-018-01

Approved: System Protection & Control Working Group Approved January 4, 2007

Approved: Markets & Operations Policy Committee Approved January 17, 2007

Action Requested: Board of Directors approve revision of Criteria 7.1 to reflect changes to satisfy new NERC standards PRC-002-01 and PRC-018-01.

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MAINTAINED BY SPCWG

Copyright © 2006 by Southwest Power Pool, Inc. All rights reserved.

SPP Criteria 7.1

(See attached file)

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Revisions Revision Date Description of Modification

2

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SPCWG, 7.1 DME

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7.0 SYSTEM PROTECTION EQUIPMENT 7.1 Disturbance Monitoring Equipment

‘Disturbance Monitoring Equipment’ (DME), as the term is used in this Section, refers to

equipment such as Digital Fault Recorders (DFR), Sequence of Events Recorders (SOE

and/or SER), Dynamic Disturbance Recorders (DDR),Phase Angle Monitors and other

devices connected to the power system for the purpose of monitoring performance of the

system. This equipment is used to capture data during disturbances defined as (i) any

perturbation to the power system, or (ii) the unexpected change in the power system that

is caused by the sudden loss of generation, transmission or interruption of load.

Disturbance monitoring equipment collect and store (a) “fault data” from a line or

equipment trip for abnormal conditions, or (b) “disturbance data” for power system

performance swings or deviations outside of a predefined operating range (frequency,

voltage, current, power, transients, etc.). Digital fault recorders (DFR) are capable of

producing date and time stamped fault records, consisting of instantaneous values of

power system quantities collected many times per cycle, for a specific period of time. In

general, DFR’s are continuously monitoring devices that use triggering methods to

capture, over a period of several cycles, specific system events, such as line trips for

fault conditions. . Sequence of Events Recorders (SER) capture and time stamp

events in the sequence in which they occur. The facility owner should be responsible for

interpreting the information from SER’s due to the equipment specific and detailed

nature of these records. Typically, SER’s record the sequence of breaker operations

needed for higher-level event reconstruction and analysis. Information provided by

SER’s may be obtained from other devices such as fault recording equipment, SCADA,

or other real time computer records. Dynamic disturbance recorders (DDR) record date

and time stamped incidents that portray power system behavior during dynamic events

such as low-frequency (0.1 Hz-3Hz) oscillations and abnormal frequency, power,

current, or voltage excursions. DDRs are also commonly referred to as dynamic swing

recorders (DSR).

7.1.1 General Minimum Technical Requirements

Disturbance Monitoring Equipment, as a minimum, must be capable of producing time

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stamped event records (some pre-fault and some post-fault data) including waveforms

for voltages and currents as well as power circuit breaker position indications. All DME

including DFRs, SERs, and DDRs as required in 7.1.2 and 7.1.4 shall be synchronized

to within 2 milliseconds or less of Universal Coordinated Time scale (UTC). Recorded

data from each disturbance shall be retrievable for at least ten calendar days per PRC-

018-1, R1-2. The Disturbance data reporting after 5-1-2007 shall be in a format which is

capable of being viewed, read and analyzed with a generic Common Format for

Transient Data Exchange for Power Systems (COMTRADE) or its successor standard.

Per PRC-002-1, new DME required per 7.1.2 shall include naming of data files in

conformance with the IEEE C37.232 Recommended Practice for Naming Time

Sequence Data Files effective 6 months after IEEE C37.232 is approved.

Disturbance Monitoring Equipment will also be required to meet the NERC PRC-002-1

and PRC-018-1 Reliability Standards.

7.1.1.1 DFR Minimum Technical Requirements

DME DFRs as required in 7.1.2 shall be capable of recording at least 5 events of not

less than 30 cycles in duration with a sampling rate of not less than 64 samples per

cycle. Event data shall be retrievable for within a period of not less than 72 hours. A

minimum of three (3) cycles of pre-disturbance data shall be recorded with each event.

Disturbance records shall be continuous until the system returns to a non-faulted

condition, or the 30 cycle minimum record duration has been reached. DME DFRs shall

record, at a minimum, the quantities listed below in a single devicerecording system.

This devicesingle recording system shall be capable of and configured to

simultaneously capture and time synchronize all required quantities at a substation for

each event in a single record..

1) One set of voltages for each operating voltage at 100 KV and above in a

substation. A set of voltages shall consist of each phase voltage

waveform. If potential devices are not required for protection or metering

purposes at a particular voltage level, then this particular voltage level

need not be monitored.

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2) For all lines, operating at 100KV and above either three phase current

waveforms or two phase current waveforms and neutral (residual) current

waveform.

3) For all autotransformers, current waveform for three phases and either

neutral/residual current waveform or current waveform in delta windings.

4) Status – circuit breaker trip circuit energization for all breakers operating

at 100KV and above.

5) Status – carrier transmit/receive if carrier relaying is used for all lines

operating at 100KV and above.

6) Date and time stamp.

7) For equipment installed after 1-1-2007, frequency, MW and MVARS shall

be recorded and displayed or be able to be derived from collected

information, using industry standard software. Sampling rate minimum for

this data shall be one sample per cycle.

8) For equipment installed after 5-1-2007, polarizing currents and voltages, if

used, on lines operating at 100KV and above.

Regarding event triggering thresholds, quantities as derived from SPP or members’

studies, when available, shall be used in lieu of those defined below. If none are clearly

defined from load flow and stability studies, then the following requirements shall be

used as a guide:

1) Phase current greater than or equal to 150% of the equipment rating.

2) Neutral (residual) current greater than or equal to 20% of the rating of the

equipment.

3) Voltage excursions greater than or equal to 10% from operating

range of equipment.

7.1.1.2 SOE/SER Minimum Technical Requirements SER’s, as required in 7.1.2, as a minimum, must be capable of producing time stamped

power circuit breaker position indications. Sequence of Events Recorders may not be

required as long as an appropriate monitoring device provides breaker indication and

meets the general technical requirements in 7.1.1

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7.1.1.3 DDR Minimum Technical Requirements

DDRs as required in 7.1.2 shall be capable of recording 960 samples per second and

shall record the true RMS value of electrical quantities at a rate of at least 6 records per

second. For DDR’s installed after January 1, 2009 continuous recording shall be

available required.

DDRs shall be capable of recording electrical quantities for each monitored element

sufficient to determine and display voltage, current, frequency, megawatts and

megavars. DDRs shall record, at a minimum, the quantities listed below:

1. One set of voltage and current for each line operated at 100kV and

above. A set shall consist of phase to neutral voltage and the

corresponding phase line current.

2. One set of voltage and current for each auto-transformer with a

secondary voltage operated at secondary side 100kV and above. A set

shall consist of phase to neutral voltage and the corresponding phase line

current.

3. Date and time stamp.

4. Frequency, MW and MVARS shall be recorded and displayed or be able

to be derived from collected information, using industry standard

software.

7.1.2 Required Location for Disturbance Monitoring Equipment Disturbance Monitoring EquipmentDFR, DDR and SER capabilities arewill be required at

all new EHV substations, operated at 345kV or higher, and all new generating stations of

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400 MVA or greater placed in service after January 1, 2002. In addition, any new

substation placed in service after January 1, 2002 containing six (6) or more lines

operating at 100 KV and above will be required to have DMEDFR,DDR, and SER

capabilities. However, when additional lines placed in service after January 1, 2002 are

added to an existing substation that results in six (6) or more total lines, then DME DFRs

and SERs shall be required for monitoring all elements within the substation as defined

in 7.1.1. 1 and 7.1.1.2. These requirements may be waived at SPP’s discretion, if DME a

DFR is already located at an adjacent substation.

DDR capabilities are required at all new EHV substations, operated at 345kV or higher,

and all new generating stations stations of 400 MVA or greater placed in service after

January 1, 2008. In addition, any new substation placed in placed in service after

January 1, 2008 containing six (6) or more lines operating at 100 KV and above will be

required to have DDR capabilities. However, when additional lines placed in service

after January 1, 2008 are added to an existing substation that results in six (6) or more

total lines, then DDR shall be required for monitoring all elements within the substation

as defined in 7.1.1.3 These requirements may be waived at SPP’s discretion. if a DDR is

already located at an adjacent substation.

The number, type and location of disturbance monitoring equipment will normally be the

responsibility of the facility owners based on recommendations by the owners’ studies

and this criteria. Information about installations will be provided by the facility owners to

the SPP in accordance with NERC Standards and maintained in a database by the SPP

staff for a period of at least three (3) years. The SPP System Protection and Control

Working Group (SPCWG) shall monitor this database. The Transmission Assessment

Working Group and Operating Reliability Working Group will review the database to

recommend that equipment with adequate capabilities, -- including digital fault

recorders, and dynamic disturbance recorders --be installed at critical locations

throughout the system as determined in power flow and dynamic stability studies.

7.1.3 Requirements for Testing and Maintenance Procedures

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Each facility owner shall have a documented maintenance program in place to test or

the means to periodically check the functionality of the Disturbance Monitoring

Equipment in service. These tests shall be done based on the manufacturers’

recommendation or, if less frequent, to maintain reliable operation. For newer DME’s

with self-monitoring, having SCADA reporting for a DME failure, and with successful

downloading of events occurring at least annually, then such activity and application

shall satisfy the testing and maintenance procedure requirements. A facility owner that

tests on a less frequent basis than the manufacturer’s recommendation shall provide

written justification for such a change, if requested by SPP or NERC. The facility owner

will be responsible for maintaining and providing required maintenance data for its

facilities for a minimum of three (3) years. Each facility owner will provide updates to the

SPP or NERC upon request.

7.1.4 Periodic Review of Disturbance Monitoring Equipment SPP members shall maintain a list of substations where Disturbance Monitoring

Equipment is located for generation and transmission facilities including those

designated as being critical by the Transmission Assessment and Security Working

Groups. The facility owner shall be responsible for providing required data on a form

developed by the System Protection & Control Working Group and supplied by SPP.

Required data should include type of DME, make and model of equipment, installation

location, operational status, date last tested, monitored elements, monitored devices,

and monitored electrical quantities. Each facility owner will shall provide updates to the

SPP upon request. The SPP staff will maintain and update the Disturbance Monitoring

Equipment database. The Transmission Assessment and Operating Reliability Working

Groups will review the database annually for additions and changes, specifically

checking for equipment as recommended in Section 7.1.2. The SPCWG will update, if

necessary, this System Protection Equipment Criteria every three (3) years.

7.1.5 Requests for Disturbance Data and Retention Requirements SPP shall function as a requesting agent and clearing house for the collection of data on

an as needed basis when the request is not from an SPP member. Facility owners shall

provide requested equipment lists and disturbance data within 30 business days with a

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copy of the requested information forwarded to the SPP. SPP shall provide installation

and reporting requirements to other regions and NERC within five (5) business days.

SPP members and NERC staff may also formally request data from SPP members with

a copy of the request forwarded to the SPP. Such requests will be considered to be a

request from SPP staff.

A narrative description of each disturbance, pursuant to the requirements of SPP Criteria

11 addressing System Disturbance Reporting, to be provided by the facility owner shall

include, at a minimum, a brief description of the event as identified on a form supplied by

SPP. Additional items that shall be included are the cause of the incident, its

consequences, service interrupted, corrective actions taken and any other additional

actions that may be required beyond the point in time when the analysis is completed to

include when these actions will be completed. Attachments shall be provided including

relevant information from the DME that substantiates the determination of cause(s) of

the disturbance. This information shall include all quantities based on the equipment

requirements specified in 7.1.1, Minimum Technical Requirements. Facility owners shall

retain disturbance data for a period of not less than one (1) year in a common format to

the extent possible given the different manufacturers and types of equipment.

Disturbance data recorded after 5-1-2007 shall be stored in a format which is capable of

being viewed, read and analyzed with a generic COMTRADE analysis tool or its

successor standard. However, the units of the data and source such as line, transformer

and generator terminal shall be clearly identifiable in a consistent, time-synchronized

format.

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Southwest Power Pool, Inc. MARKETS AND OPERATIONS POLICY COMMITTEE

Recommendation to the Board of Directors January 30, 2007

2006-2016 SPP Transmission Expansion Plan

Organizational Roster SPP Staff, Keith Tynes Manager, Engineering Planning

Background The SPP OATT Attachment O requires the Transmission Provider (SPP) “independently perform regional transmission planning studies. These studies shall assess the reliability and economic operation of the SPP Transmission System” – sec 2.0. In response to Attachment O, SPP consulted with the TWG to develop an approved study scope for the 2006-2016 SPP Transmission Expansion Plan (2006 STEP) during the November 9, 2005 TWG meeting. As directed by Attachment O, SPP Staff collaborated with stakeholders to develop mitigations to develop this report along with a list of identified operational reliability constraints and acceptable mitigations.

In addition to several separate TWG meetings with SPP staff through out 2006, SPP conducted an open stakeholder summit May 18th in Kansas City, MO where over 100 people discussed current study progress, identified reliability issues and possible solutions going forward. Another open stakeholder summit conference call and WebEx was conducted August 16th to review and discuss identified transmission improvement solutions.

The approval process began November 8, 2006 where SPP provided the TWG with a first draft of the SPP Transmission Expansion Plan 2006-2016 report. On November 15, 2006 a WebEx was held for public review of the draft SPP Transmission Expansion Plan 2006-2016 report. On November 30, 2006 the TWG reviewed the report and recommended further changes. On December 11, 2006 the TWG endorsed the SPP Transmission Expansion Plan 2006-2016 report, as modified.

RECOMMENDATION #1: The SPP Staff requests MOPC endorse the 2006-2016 SPP Transmission Expansion Plan for SPP Board of Directors approval as the appropriate SPP Staff completion of the requirements of Attachment O to assess the reliability and economic operation of the SPP Transmission System. The TWG supports this

RECOMMENDATION #2: The SPP Staff requests that the MOPC endorse the list of reliability projects in Appendix ‘B’ from the 2006 SPP Transmission Expansion Plan that the SPP BOD, in order to maintain reliability, will authorize and direct the start of construction. The TWG supports this SPP Staff recommendation.

Supported: Transmission Working Group Endorsed unopposed.

December 11, 2006

Approved: Markets and Operations Policy Committee January 17, 2007

Recommendation #1 Approved Unanimously with “If a project sponsor steps forward” added to the beginning of the last paragraph on Page 140 of the Plan.

Recommendation #2 and additionally to remand recommendation to the TWG to consider extending Appendix B beyond a 2-year commitment window for reliability projects through the entire planning horizon in the next Expansion Plan. Approved with one abstention, Redbud.

Action Requested: Approve Recommendations #1 & #2.

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The 2006-2016 SPP Transmission Expansion Plan can be accessed at: SPP Transmission Expansion Plan

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Southwest Power Pool, Inc. MARKETS AND OPERATIONS POLICY COMMITTEE

Recommendation to the Board of Directors January 30, 2007

SPP OATT 1.3h “Base Plan Upgrades”

Background SPP Tariff definition 1.3h, Base Plan Upgrades: “Those upgrades included in and constructed pursuant to the SPP Transmission Expansion Plan in order to ensure the reliability of the Transmission System. Base Plan Upgrades shall also include those upgrades required for new or changed Designated Resources to the extent allowed for in Attachment J to this Tariff.” April 2006, the MOPC considered the recommendations of the Base Plan Guidelines Task Force and approved “Option C” and the “Transition plan to Option C” clarifying guidelines to be used by Southwest Power Pool (SPP) to classify transmission projects for Base Plan funding pursuant to the SPP Tariff. “Option C” and “Transition Plan to Option C” are summarized as follows:

• A definition, “Zonal Reliability Upgrades” will be added to the tariff. • SPP and NERC Reliability Standards will be applied for the identification of Base Plan Upgrades. • Local Transmission Owner planning standards will be used to identify “Zonal Reliability

Upgrades” that will go exclusively into the zonal rates. • The “Transition Plan” allows Transmission Owner projects with in service dates in 2006-2007

window based on local Transmission Owner planning standards which have been submitted to SPP be included as Base Plan Upgrades until the appropriate SPP tariff language changes are made.

• Any upgrades with in service dates beyond this window will be evaluated according to the proposed new tariff language outlined in “Option C”.

Analysis SPP Staff reviewed the list of all identified transmission reliability upgrades from the SPP Transmission Expansion Plan and evaluated them in accordance with “Option C” and “Transition Plan to Option C”. In the spirit of a two year window, transmission reliability upgrades with requiring commitments between the dates of 2006 through 2008 were reviewed for potential classification as Base Plan Upgrades according to the existing tariff language. Because no tariff changes were made to implement the “Zonal Reliability Upgrades”, projects that met Transmission Owner criteria submitted to SPP were also considered as potential Base Plan Upgrades during this review. Any projects with a construction window beyond the date of 2009 were not evaluated in this process. Recommendation The SPP Staff recommends that the MOPC endorse the list of Base Plan Upgrades consistent with the intent of the tariff, “Option C”, and “Transition Plan to Option C”. Approved: Markets and Operations Policy Committee approved

endorsement of the Base Plan Upgrades unanimously. January 17, 2007

Action Requested: Endorse list of proposed Base Plan Upgrades.

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Explanation of proposed 2007, first QTR Base Plan Upgrades –

The SPP Regional State Committee recommended all SPP Base Plan Upgrades undergo an open review and comment process. To maintain the open review and feedback process, any comments submitted to SPP will be tracked and posted up and until each reviewing committee or Board of Directors meeting.

In your review, please note the following differences between this proposed Base Plan Upgrades list and “Appendix B” of the TWG endorsed 2006 SPP Transmission Expansion Plan (2006 STEP):

endorsed 2006 STEP requiring commitments in 2007 and 2008 with exception of projects identified as “Existing Facilities” under section 1.11a of the SPP OATT. In addition to the previously mention projects from “Appendix B”, the Base Plan Upgrades list also includes all Aggregate Study Base Plan Upgrades.2) STEP “Appendix B” includes all reliability projects with construction lead times in 2007 and 2008 AND ALSO INCLUDES projects identified as “Existing Facilities” under section 1.11a of the SPP OATT. “Appendix B” does not include Aggregate Study Base Plan Upgrades.

These proposed Base Plan Upgrades will be reviewed during the MOPC January 16th, 17th meeting prior to a review by the RSC on January 29th and then submitted to the SPP Board for approval on January 30th.

** The [2006 Approved Base Plan List] Excel worksheet tab lists all transmission reliability improvements approved for Base Plan Upgrade status on April 25, 2006.

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2007, First Quarter: Recommended Base Plan Upgrades Green On Schedule

The following are transmission reliability improvements that meet criteria Orange Unknown

for designation as Base Plan Upgrades in accordance with the proposed Red Delayed

Base Plan Guidelines Task Force report and the SPP OATT.

Area Project Name In-Service Date

2006 Expansion Plan Date

Cost EstimateOn

Schedule Approved

WERE Line - Cities Service - 3rd & VanBuren 69 kV Mar-06 - $1,700,000WERE Line - Circle - Hutchinson Energy Center 115 kV Apr-06 - $300,000 Apr-06AEPW Line - Tontitown - Elm Springs REC 161 kV May-06 - $640,000 Apr-06WERE Line - Midwest Solvent Jct 1 - Atchison Jct 2 69 kV May-06 - $35,000 Apr-06AEPW Line - Lone Star South - Pittsburg 138 kV Jun-06 - $50,000AEPW Device - Arsenal Hill 138 kV Jun-06 - $432,000 Apr-06AEPW Device - Catoosa 138 kV Jun-06 - $394,000 Apr-06AEPW Line - Carthage REC - Carthage T 138 kV Jun-06 - $690,000 Apr-06MIPU Line - Craig Interconnection 161 kV Jun-06 - $75,000 Apr-06OKGE Line - Reno - Sunny Lane 69 kV Jun-06 - $100,000 Apr-06OKGE Line - Richards Tap - Richards 138 kV Jun-06 - $1,000,000 Apr-06OKGE Line - Van Buren AVEC - VBI 69 kV Jun-06 - $50,000 Apr-06OKGE Line - Brown - Explorer Tap 138 kV Ckt 1 Jun-06 - $25,031SWPS XFR - Bailey Co 115/69 kV Jun-06 - $2,200,000 Apr-06SWPS XFR - Denver City 115/69 kV Jun-06 - $2,200,000 Apr-06SWPS XFR - Kress 115/69 kV Jun-06 Jun-07 $1,250,000 Apr-06WFEC Device - Rush Springs 69 kV Jun-06 - $90,000WERE Multi - Morris - McDowell 230 kV Jul-06 - $7,224,000 Apr-06WERE XFR - Butler 138/69 kV Aug-06 - $1,600,000 Apr-06MIPU Line - Nevada 161 - Nevada Plant 69 kV Oct-06 - $536,000 Apr-06KCPL Line - Tomahawk - Bendix 161 kV Dec-06 - $528,600 Apr-06SWPS XFR - Hockley 115/69 kV Dec-06 - $2,750,000 Apr-06WERE Device - Clearwater 138 kV Dec-06 - $1,000,000 Apr-06WERE Device - UDALL 2 69 kV Dec-06 - $525,000 Apr-06WERE Multi - HEC - 43rd & Lorraine - Tower 33 69 kV Dec-06 - $2,400,000 Apr-06OKGE Line - NE Enid - Glenwood 138 kV Dec-06 - $3,732,000OKGE Line - Razorback - Short Mountain 69 kV Dec-06 - $4,791,277

AEPW Line - Siloam Springs - Chamber Springs 161 kV May-07 - $6,627,225 Apr-06AEPW Line - South Shreveport - SW Shreveport 138 kV May-07 - $130,000 Apr-06WFEC Device - Pink Southwest 138 kV - Apr-07 $216,000WFEC Device - Snyder 69 kV - Apr-07 $100,000AEPW Line - 53rd & Garnett N. Tap - Tulsa Southeast 138 kV Jun-07 - $63,000 Apr-06AEPW Line - Knox Lee - Oak Hill #2 138 kV Jun-07 Jun-10 $100,000 Apr-06AEPW Line - Elk City - Elk City 69 kV - Jun-07 $100,000AEPW Line - Porter Hill - Elgin Junction 69 kV - Jun-07 $200,000AEPW Device - Broken Arrow Water 69 kV - Jun-07 $550,000AEPW Device - Hobart 69 kV - Jun-07 $550,000AEPW Line - Northwest Texarkana - Alumax Tap 138 kV Jun-08 Jun-07 $1,750,000EMDE Line - ReinMiller - Tipton Ford 161 kV Jun-07 - $3,215,000 Apr-06GRDA XFR - Stilwell City 161/69 kV Jun-07 - $1,800,000 Apr-06KCPL Device - South Waverly 161 kV Jun-07 - $611,000 Apr-06KCPL Line - Stilwell - Antioch 161 kV Jun-07 - $892,600 Apr-06MIPU Line - Lake Road to Industrial Park 161 kV Jun-09 Jun-07 $250,000OKGE Line - Richards - Piedmont 138 kV Jun-07 - $3,800,000 Apr-06SWPA XFR - Norfork 161/69 kV Jun-07 - $1,300,000 Apr-06SWPS XFR - Terry Co 115/69 kV Jun-07 - $2,375,000 Apr-06SWPS XFR - Carlsbad Int 115/69 kV - Jun-07 $2,750,000SWPS XFR - Crosby Co Int 115/69 kV - Jun-07 $1,000,000

Base Plan Upgrade identified in the SPP Transmission Expansion Planning Process

2006

2007

SWPS XFR - Curry Co Int 115/69 kV - Jun-07 $1,000,000SWPS XFR - Gaines Co Int 115/69 kV - Jun-07 $2,750,000SWPS Device - San Andress Sub 115 kV - Jun-07 $750,000SWPS XFR - Lubbock East 115/69 kV Jun-08 Jun-07 $2,750,000SWPS XFR - Artesia 115/69 kV Dec-10 Jun-07 $2,750,000WEPL Greensburg - Judson Large 115KV - Jun-07 $148,000WERE Device - NE Parsons 138 kV Jun-07 Jun-07 $1,000,000 Apr-06

WERE Line - Golden Plain - Gatz 69 kV - Jun-07 $590,000

WERE Line - Hesston - Golden Plain 69 kV - Jun-07 $1,250,000

WERE Line - HTI Junction - Circleville 115 kV - Jun-07 $2,360,000WERE Device - Nortonville 69 kV Cap - Jun-07 $564,000 Apr-06WERE Device - Parsons 69 kV Jul-07 Jun-07 $525,000 Apr-06WERE Device - Sunset 69 kV Jun-08 Jun-07 $550,000WERE XFR - County Line 115/69 kV Jul-09 Jun-07 $1,700,000WERE Line - Stranger Creek - Thornton Street 115 kV Jul-09 Jun-07 $2,500,000WFEC Line - ACME - W Norman 69 kV - Jun-07 $912,000WFEC Device - Cashion 69 kV - Jun-07 $108,000WFEC Device - Comanche 138 kV - Jun-07 $350,000OKGE Line - Westmoore - Pennsylvania 138 kV Jun-09 Oct-07 $250,000SWPS XFR - Hale Co 115/69 kV Dec-07 - $2,900,000 Apr-06WFEC Line - Bradley - Rush Springs 69 kV - Dec-07 $1,656,000WFEC Line - Elmore - Wallville 69 kV - Dec-07 $1,488,000

AEPW Line - Bann - Kings Highway 69 kV Jun-08 - $50,000AEPW Multi - Fayetteville 69 to 161 kV conversion Jun-08 Jun-08 $21,000,000EMDE Multi - Riverdale - Ozarks 161 kV Jun-08 Jun-10 $14,057,000EMDE Line - Sub 167 - Riverton - Sub 406 - Riverton S 69 kV - Jun-08 $20,000OKGE Line - Etowah - Tribbey 69 kV Jun-08 - $1,900,000SWPS XFR - Mustang Sta N. 230/115 kV - Jun-08 $3,000,000SWPS Device - Bowers 69 kV - Jun-08 $300,000WERE Line - Coffeyville - CRA 69 kV - Jun-08 $250,000WERE Line - Dearing - Coffeyville 69 kV - Jun-08 $390,000WFEC Line - Sayre - Morewood 138 kV - Jun-08 $12,000,000WERE Line - Murry Gill Energy Center - MacArthur 69 kV Jul-07 Jun-08 $143,000WERE Multi - Hutchinson 115 kV conversion Dec-08 - $1,900,000MIDW Multi - Knoll - Hays - Vine 115 kV Jun-09 Jun-08 $536,000SWPS XFR - Cochran 115/69 kV Sep-09 Jun-08 $2,750,000MIPU Line - Blue Springs - Duncan Road 161 kV Jun-10 Jun-08 $1,605,500SWPS XFR - NE Hereford 115/69 kV Jun-10 Jun-08 $1,750,000WERE Device - 3rd & VanBuren 115 kV Jul-10 Jun-08 $500,000

Total: $155,700,233

Area Project Name In-Service Date Cost Estimate

On Schedule Approved

AEPW Line-EAST CENTRAL HENRYETTA - OKMULGEE 138KV Apr-06 $52,277 N/AAEPW Line - Okmulgee - Weleetka 138 kV Apr-06 $84,000 N/AAEPW Line - Cache - Snyder 138kV Jun-08 $73,348 N/AAEPW Line - NW Henderson - Oak Hill 138 kV Jun-08 $75,000 N/AOKGE Line - Wind Farm - Mooreland 138 kV Jun-08 $120,000 N/AWFEC Line - Wind Farm - Mooreland 138 kV Jun-08 $750,000 N/A

Total: $1,154,625

Base Plan Upgrade recommendations identified in the Aggregates Study Process

2008

2007 First Quarter: Potential Base Plan Upgrades

The following are transmission reliability improvements that meet criteria for designation as Base Plan Upgrades

in accordance with the proposed Base Plan Guidelines Task Force report and the SPP Open Access Transmission Tariff.Note: Cost estimates in yellow are SPP Staff estimates

Potential Base Plan Upgrade identified in the SPP Transmission Expansion Planning ProcessArea Project Name In-Service

Date

2006 Expansion Plan Date

Cost Estimate Base Plan Reason Project Description/Comments Project Justification

AEPW Line - Lone Star South - Pittsburg 138 kV 06/01/06 - $50,000 Identified in the 2004_2005 SPP Expansion Plan as needed in 6/1/2006 TPL002 Replace CT Lone Star South-Pittsburg 138 kV over load for an outage of Petty-Chapel Hill Rec

138

AEPW Line - Elk City - Elk City 69 kV 06/1/07 * 06/01/07 $100,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007TPL002

Replace CTS & jumpers. Limits on AEP end will be 600Aswitches and Breaker

To address overloads @ Elk City 69 - Elk City for the MOREWOOD - MORWOOD 69kv outage

AEPW Line - Porter Hill - Elgin Junction 69 kV 06/1/07 * 06/01/07 $200,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007TPL002

Replace Switches & reset CT @ Elgin Jct. Replace switches @Porter Hill. $200,000 12 month lead time

To address overload @Porter Hill - Elgin Junction 1 for Lawton Eastside - LawtonGore North outage

AEPW Device - Broken Arrow Water 69 kV 06/1/07 * 06/01/07 $550,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007TPL002 Install 6 MVA Cap at Broken Arrow water 6 MVAR To address low voltages @Broken Arrow Water & Coweta for an outage of Tulsa SE

transformer

AEPW Device - Hobart 69 kV 06/1/07 * 06/01/07 $550,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007TPL002 Install 4.8 MVAR cap at Hobart 54128 To address low voltage @Hobart for the Hobart - Hobart Junction 69kV outage

AEPW Line - Northwest Texarkana - Alumax Tap 138 kV 06/01/08 06/01/07 $1,750,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007TPL002

Rebuild 2 miles of 1590 ACAR with 2156 ACSR, Replacewavetrap & jumpers with 2156 ACSR. Replace Switch 2285 @Alumax Tap.

To addres overload @Northwest Texarkana - Alumax Tap 1 for SPP-AEPW-29outage

AEPW Line - Bann - Kings Highway 69 kV 06/01/08 - $50,000 Identified in the 2004_2005 SPP Expansion Plan as needed in 6/1/2008 TPL002 Replace Switch in King Hwy substation Bann-Kings Highway 69 kV for loads for outage Bann-SE Texarkana 138 kV line

AEPW Multi - Fayetteville 69 to 161 kV conversion 06/01/08 06/01/08 $21,000,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2008TPL002

Convert S. Fayetteville - Fayetteville - Dyess 69 KV line to 161kV

Dyess-S Springdale 161kv overloads conductor for outage of Chamber Springs-Farmington 161 kV

EMDE Multi - Riverdale - Ozarks 161 kV 06/01/08 06/01/10 $14,057,000 Identified in the2006 SPP Expansion Plan as needed in 6/1/2010TPL002

Build 161 kV line from AECI's Riverdale substation to a newsubstation at Ozark. Install a 100 MVA 161/69 Auto-xfmr in theOzark substation. Split the 69 kV line from Forsyth to Ozark#434 at this new substation.

Low voltage at the Ozark #330 substation during the outage of Blackhawk #415 toOzark #330. Also, under normal conditions EDE exceeds their contract limit on theBlackhawk to Jamevilles interconnection with AECI.

EMDE Line - Sub 167 - Riverton - Sub 406 - Riverton S 69 kV 06/1/08 * 06/01/08 $20,000 Identified in the2006 SPP Expansion Plan as needed in 6/1/2008TPL002

Change Relay Settings and change jumpers on switch atRiverton Sub #406

To address overload @SUB 167 - RIVERTON - SUB 406 - RIVERTON SOUTH 1 foroutage of HOCKERVILLE 161/69 Xfr

MIDW Multi - Knoll - Hays - Vine 115 kV 06/30/09 06/01/08 $536,000 Identified in the 2006 SPP Expansion Plan as needed in 2008 TPL002

Tap Vine - Knoll 115 kV and reconductor Hays Plant - VineStreet and S. Hays - Hays Plant

To address overload of Vine - Hays Plant overload for the Knoll 230/115 kVTransformer outage

MIPU Line - Lake Road to Industrial Park 161 kV 06/01/09 06/01/07 $250,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007TPL002 Replace existing structures to allow for higher rating To address overload of Lake Road to Industrial Park 161 kV for outage of St. Joseph

to Woodbine 161 kV

MIPU

Line - Blue Springs - Duncan Road 161 kV

06/01/10 06/01/08 $1,605,500 Itentified by Tarrif Studies group as an Expansion Plan project needed 6/1/2008 Upgrade to conductor Bundled Drake

Identified as Expansion Plan project by the Tarrif Studies group in AGS 2006-1 BlueSprins East to Duncan 161 kV line over loads for an outage of PLEASANT HILL ()345/161/13.8KV TRANSFORMER CKT 1 over load in years 2006 throough 2010

OKGE Line - Brown - Explorer Tap 138 kV Ckt 1 06/01/06 $25,031 TO Study - NERC TPL-002 Upgrade CT's at Brown Substation

The 2010 Summer Peak Contingency Analysis indicates that the loss of the Bus #55120 RUSSET 138kV to Bus # 55147 GLASSES4 138 line causes and overload onthe Bus # 52802 S BROWN 138kV to 55157 BROWN 138kV section. To mitigate an(N-1) condition as determined by SPP Planning standards and NERC TPL-002-0.OGE operations also seen very low voltage during summer 2005 due to the WFECHugo plant trip off.

OKGE Line - NE Enid - Glenwood 138 kV 12/31/06 - $3,732,000 Project to meet OG&E Operating Practice S3-5Part of a long term project per K Study 5140.3 to enhance thetransmission system in Enid, OK. This is the last phase of theproject.

Project to meet OG&E Operating Practice S3-5, which is part of OG&E PlanningCriteria, which qualifies this project for Regional Cost Allocation and inclusion in thePlant. [Due to OGE K5140.3 study in 2001 that identified violations of OGE S3-5operatin

OKGE Line - Razorback - Short Mountain 69 kV 12/31/06 - $4,791,277 Project to meet OGE's operating guides S3-5. New 69(161)kV transmission line from Razorback to ShortMountain

As a result of OGE internal K study 10086 for future conversion. Supporting Study hasbeen submitted to SPP in the past. Project was initiated to close the radialtransmission lines at Short Mountain and Razorback Substation per OGE's operatingguides S3

OKGE Line - Etowah - Tribbey 69 kV 06/01/08 - $1,900,000 TO Study - NERC TPL-002

Close NO switch of Etowah-Tribbey by rebuilding Etowah andinstalling 69kV breakers. NOTE: Overloads Midwest - Franklinso it must take place after the Midwest - Franklin project iscomplete

Low voltage around Spring Hill, Little Axe, Etowah, Macomoc for OKGEMTL-24.Violates NERC TPL-002-0 and SPP Criteria 3.4.

OKGE Line - Westmoore - Pennsylvania 138 kV 06/01/09 10/01/07 $250,000 Identified in the 2006 SPP Expansion Plan as needed in 10/1/2007 TPL002

Replace the disconnect switches for breaker 108 atPennsylvania Substation. Replace the 1200A trap. IncreaseCTR. Relay replacement may be required.

Identifid By the AG study as an Expansion Plan Project being need in 2007 fall for anoutage CZECH HALL -CIMARRON 138 or an outage of CZECH HALL - INDIANHILLS 138

SWPS XFR - Carlsbad Int 115/69 kV 06/1/07 * 06/01/07 $2,750,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007TPL002 Upgrade 115/69 kV transformer. To address overload @Carlsbad 115/69 kV transformer 1 & 2 for outage

SWPS XFR - Crosby Co Int 115/69 kV 06/1/07 * 06/01/07 $1,000,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007TPL002 Add third transformer from spare stock To address overload @Crosby 115/69 kV transformer 1 & 2 for outage of the other

Crosby transformer

SWPS XFR - Curry Co Int 115/69 kV 06/1/07 * 06/01/07 $1,000,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007TPL002 Add third transformer from spare stock To address overload @Curry 115/69 kV transformer 1&2 for outage

SWPS XFR - Gaines Co Int 115/69 kV 06/1/07 * 06/01/07 $2,750,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007TPL002 Replace both gaines transformers with 84 MVA xf To address overload @Northwest - Gaines 115/69 kV transformer 1 & 2 for outage of

one of Graines XF overloads the other

SWPS Device - San Andress Sub 115 kV 06/1/07 * 06/01/07 $750,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007TPL002

Install 1 - 14.4 Mvar cap bank on the 115 kV bus at San Andress

Voltage below critera at San Andress bus for outage os San Andress toDenver CityInterchange S

SWPS XFR - Lubbock East 115/69 kV 06/01/08 06/01/07 $2,750,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007TPL002 Upgrade both existing transformer To address loss of parallel transformer

91 of 101

2007 First Quarter: Potential Base Plan Upgrades

SWPS XFR - Mustang Sta N. 230/115 kV 06/1/08 * 06/01/08 $3,000,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2008TPL002 Upgrade Transformer 230/115 kV 252/289 MVA To address overload @Mustang 230/115 kV transformer 1 for outage

SWPS Device - Bowers 69 kV 06/1/08 * 06/01/08 $300,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2008TPL002 INSTALL 14.4 MVAR CAP BOWERS 69 KV Voltage below criteria at the Canadian bus for outage of Bowers to Grapevine 115kV

SWPS XFR - Cochran 115/69 kV 09/01/09 06/01/08 $2,750,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2008TPL002 Upgrade both existing transformer To address loss of parallel transformer

SWPS XFR - Artesia 115/69 kV 12/01/10 06/01/07 $2,750,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007TPL002 Upgrade both existing transformer To address loss of parallel transformer

SWPS XFR - NE Hereford 115/69 kV 06/01/10 06/01/08 $1,750,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2008TPL002 Add second 115/69 kV transformer

NE Herford 115/69 kV XF overload for outage of Herferd to Deaf Smith CountyInterchange 115 kV this also relives the overload of the Hereford Interchange 115/69kV XF for the outage of NE Herford 115/69 kV XF

WEPL Greensburg - Judson Large 115KV 06/1/07 * 06/01/07 $148,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007TPL002 Replace relays (upgrade protection system) To address overload of the GREENSBURG - JUDSON LARGE 115KV line for the

outage of the Mullergren-Spearville 230 KV

WERE Line - Cities Service - 3rd & VanBuren 69 kV 03/01/06 - $1,700,000 TO Study Identified as Needed June 2006Tear down / Rebuild 3.18-mile line using 795 kcmil ACSR;Project is part of a long range plan to correct service issues inthe City of Hutchinson area.

Addresses overloads for loss of Circle-Davis 115 kV line, NERC Reliability StandardTPL-002-0. Transmission Operating Directive 1205 no longer effective.

WERE Line - Golden Plain - Gatz 69 kV 06/1/07 * 06/01/07 $590,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007TPL002 Rebuild Gatz - Golden Plain Tap 69 kV line. To address line overload issues for the loss of Halstead (57736) - Mud Creek (57744)

69 kV line.

WERE Line - Hesston - Golden Plain 69 kV 06/1/07 * 06/01/07 $1,250,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007TPL002 Rebuild Hesston - Golden Plain Tap 69 kV line. To address line overload issues for the loss of Halstead (57736) - Mud Creek (57744)

69 kV line.

WERE Line - HTI Junction - Circleville 115 kV 06/1/07 * 06/01/07 $2,360,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007TPL002 Rebuild 115 kV line See Westar Five-Year Transmission Construction Recommendations, August

12,2005, P. 11

WERE Line - Murry Gill Energy Center - MacArthur 69 kV 07/01/07 06/01/08 $143,000 Identified in the2006 SPP Expansion Plan as needed in 6/1/2008TPL002

Replace bus, jumpers and disconnect switches at MacArthur 69kV substation to increase line capacity to conductor rating

To address line overload issues for the loss of Gill Energy Center East (57795) - GillEnergy Center Jcn (57798) 69 kV line.

WERE Line - Coffeyville - CRA 69 kV 06/1/08 * 06/01/08 $250,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2008TPL002 Rebuild Coffeyville - CRA 69 kV line. To address line overload issues for the loss of CRA (57685) - Liberty (57697) 69 kV

line.

WERE Line - Dearing - Coffeyville 69 kV 06/1/08 * 06/01/08 $390,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2008TPL002 Rebuild Dearing - Coffeyville 69 kV line. To address line overload issues for the loss of CRA (57685) - Liberty (57697) 69 kV

line.

WERE Device - Sunset 69 kV 06/30/08 06/01/07 $550,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007TPL002 Install 10 Mvar cap at Sunset 69 kV (bus # 57844) Voltage support needed due to low voltage from loss of SWPS #1 and loss of

Brookline-to-Morgan 345 kV line.

WERE Multi - Hutchinson 115 kV conversion 12/31/08 - $1,900,000 TO study identified as needed June 2006. Project completes theconversion of the 69 kV system in Hutchinson to 115 kV.

Convert the HEC - 43rd&Lorraine - Tower 33 - Meadowlark -3rd&VanBuren 69 kV to 115 kV

TO study identified as needed June 2006. Project completes the conversion of the 69kV system in Hutchinson to 115 kV. Required for compliance with NERC ReliabilityStandard TPL-002-0. See Westar Five-Year Transmission ConstructionRecommendations, August 12,2005, P. 23.

WERE XFR - County Line 115/69 kV 07/01/09 06/01/07 $1,700,000 Identified in the 2006 SPP Expansion Plan as needed in 2007 TPL002

Replace existing 66 MVA 115-69 kV transformer with 112 MVAunit

To address overload issue at County Line 115 KV (57153) for the loss of StrangerCreek 345/115/14.4kV XFMR (56772/57268/56811).

WERE Line - Stranger Creek - Thornton Street 115 kV 07/01/09 06/01/07 $2,500,000 Identified in the 2006 SPP Expansion Plan as needed in 2007 TPL002

New 115 kV Line from Stranger Creek (57268) to ThorntonStreet (57272).

To address low voltage issues @ Hallmark 115 kV (57242) & Lansing 115 kV (57246)for the loss of the Jarbalo (57244) - Lansing (57246) 115 kV line. Also addresses lowvoltage issues @ Parallel 115 kV (57218), Walnut 115 kV (57220), Arnold 69 kV(57471), Atchison Castings 69 kV (57474), Maur Hill 69 kV (57476), Midwest Grain 69kV (57477), Muscotah 69 kV (57480), Nortonville 69 kV (57481), Wathena 69 kV(57105) for the loss of Arnold to Stranger Creek 115 kV line. Also addresses overloadissues.

WERE Device - 3rd & VanBuren 115 kV 07/01/10 06/01/08 $500,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2008TPL002 Install switched capacitor bank

To address Westar voltage criteria violationat 3rd & Van Buren 115 kV (bus # 57435),43rd & Lorraine 115 kV (bus # 57440) & Meadowlark 115 kV (bus # 57441) for theloss of Hutchinson Energy Center (bus # 57419) - 43rd & Lorraine (bus # 57440) 115KV line.

WFEC Device - Rush Springs 69 kV 06/01/06 - $90,000 Identified in the 2004_2005 SPP Expansion Plan as needed in 6/1/2006 TPL-002 Install switched cap 3MVar To address low voltage @ Rush Springs due to outage of Fletcher to Marlow 69 kV

line

WFEC Line - ACME - W Norman 69 kV 06/1/07 * 06/01/07 $912,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007TPL002

Reconductor 3.8 miles from 3/0 ACSR to 795 ACSR.RateA=81MVA, RateB=106MVA

To relieve overload on ACME to W Norman 69 kV for outage of Canandian 138/69 kVtransformer

WFEC Device - Cashion 69 kV 06/1/07 * 06/01/07 $108,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007TPL002 Install 2 - 3 MVAR capacitors at Cashion 69 kV bus To address low voltage @ Cashion 69 kV for loss of Dover to Dover Junction 69 kV

line

WFEC Device - Comanche 138 kV 06/1/07 * 06/01/07 $350,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007TPL002 Install 12 MVAR Capacitor at Comanche 138 kV bus Identified in Aggregate Study by Tariff Studies Group as a reliability project for the

SPP Expansion Plan

WFEC Device - Pink Southwest 138 kV 06/1/07 * 04/01/07 $216,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007TPL002 Install 6 MVAR capacitor at Pink Southwest 138 kV bus To address low voltage @ Pink Southwest 138 kV for outage of

WFEC Device - Snyder 69 kV 06/1/07 * 04/01/07 $100,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007TPL002 Upgrade 12 Mvar cap bank at Snyder to 24Mvar Identified in Aggregate Study by Tariff Studies Group as a reliability project for the

SPP Expansion Plan

WFEC Line - Bradley - Rush Springs 69 kV 12/1/07 * 12/01/07 $1,656,000 Identified in the 2006 SPP Expansion Plan as needed in 12/1/2007 TPL002

Reconductor 6.9 miles from 1/0 ACSR to 795 ACSR.RateA=81MVA, RateB=106MVA

To relieve overload on Bradley to Rush Springs 69 kV for outage of Elmore to Wallville69 kV line.

WFEC Line - Elmore - Wallville 69 kV 12/1/07 * 12/01/07 $1,488,000 Identified in the 2006 SPP Expansion Plan as needed in 12/1/2007 TPL002

Reconductor 6.2 miles from 1/0 ACSR to 336 ACSR.RateA=47MVA, RateB=61MVA To relieve overload for outage of Bradley to Rush Springs 69 kV line

WFEC Line - Sayre - Morewood 138 kV 06/1/08 * 06/01/08 $12,000,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2008TPL002

Build new 138 kV line Sayre to Erick. Convert voltage for Erick-Sweetwater-Durham-Brantley-Morewood-SW to 138 kV. AddSayre PSO interconnect at 138 kV (assumed 15 miles of newline, 75 miles of voltage conv)

To relieve overload for outage of Morwood 69 kV line

* Indicates that In-Service date is assumed to be date identified in SPP Expansion Plan

Total: $103,867,808

Base Plan Upgrade recommendations identified in the Aggregates Study ProcessArea Project Name In-Service

Date Cost Estimate Base Plan Reason Project Description/Comments Project Justification

AEPW Line-EAST CENTRAL HENRYETTA - OKMULGEE 138KV 04/01/06 $52,277 Transmission Service Request Replace Okmulgee wavetrap per 2005-AG2AEPW Line - Okmulgee - Weleetka 138 kV 04/01/06 $84,000 Transmission Service Request Replace Weleetka wavetrap per 2005-AG2AEPW Line - Cache - Snyder 138kV 06/01/08 $73,348 Transmission Service Request Replace Snyder wavetrap per 2006-AG1AEPW Line - NW Henderson - Oak Hill 138 kV 06/01/08 $75,000 Transmission Service Request Replace wavetrap and reset CTs @ NW Henderson. per 2005-AG1

OKGE Line - Wind Farm - Mooreland 138 kV 06/01/08 $120,000 Transmission Service Request Upgrade conductor between Mooreland 138 and Wind Farm138 with 795AS33 per 2006-AG1

WFEC Line - Wind Farm - Mooreland 138 kV 06/01/08 $750,000 Transmission Service Request Upgrade terminal equipment at Mooreland per 2006-AG1

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Base Plan List as of April 25, 2006

Note: Projects that have had a change in justification for reliability need since approved (4-25-06)

Area Project Name In-Service Date

2006 Expansion Plan Date

Cost Estimate Base Plan Reason Project Description/Comments Project Justification

AEPW Line - Tontitown - Elm Springs REC 161 kV 05/01/06 - $640,000 Identified in the 2004_2005 SPP Expansion Plan as needed in 6/1/2007 TPL002

Rebuild line with 2-397 ACSR. Replace 1200 A switch 1045, and bus Elm Springs. Tontitown-Elm Spring 161 kV line overload for outage of Dyess-Tontitiown 161 kV

AEPW Device - Arsenal Hill 138 kV 06/01/06 - $432,000 Required to meet Transmission owner Criteria Install switched capacitor bank

Power factor correction, voltage support, and VAR supply. Supplying VARs to thesystem enables generation to reduce VAR output, so that during contingencies,generators can rapidly respond with VAR support. The AEP Transmission PlanningReliability Criteria

AEPW Device - Catoosa 138 kV 06/01/06 - $394,000 Required to meet Transmission owner Criteria Install switched capacitor bank

Power factor correction, voltage support, and VAR supply. Supplying VARs to thesystem enables generation to reduce VAR output, so that during contingencies,generators can rapidly respond with VAR support. The AEP Transmission PlanningReliability Cri

AEPW Line - Carthage REC - Carthage T 138 kV 06/01/06 - $690,000 Identified in the 2004_2005 SPP Expansion Plan as needed in 6/1/2007 TPL002 Reconductor line with 1272 ACSR Carthage REC-Carthage overloads for an outage Keatchie-Stonewall 138 kV

AEPW Line - Siloam Springs - Chamber Springs 161 kV 05/01/07 - $6,627,225 Identified in the 2004_2005 SPP Expansion Plan as needed in 6/1/2007 TPL002

New 161 line, Terminal equipment atChamber Spring and Siloam Springs

Flint Creek-Chamber Springs 161 kV and Flint Creek -Tontitown 161 kV overload foroutage of Chamber Springs - Clarksville 345 kV

AEPW Line - South Shreveport - SW Shreveport 138 kV 05/01/07 - $130,000 Identified in the 2004_2005 SPP Expansion Plan as needed in 6/1/2010 TPL002 Replace wavetrap at South Shreveport To address overloads due to loss of Southwest Shreveport-Western Electric-Stonewall

AEPW Line - 53rd & Garnett N. Tap - Tulsa Southeast 138 kV 06/01/07 - $63,000 Identified in the 2004_2005 SPP Expansion Plan as needed in 6/1/2006 TPL002 Replace 3 switches 53rd & Garnett North Tap-Tulsa SE over load for an outage of Oneta- 12 ST. & Lynn

Lane

AEPW Line - Knox Lee - Oak Hill #2 138 kV 06/01/07 06/01/10 $100,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2010 TPL002 Replace relay, wave trap at Knoxlee To address the overload of Knox Lee to Oak Hill 138 kV for the outage of Knox Lee to

Monroe Corners REC 138 kV

AEPW Line - Hart's Island - Port Robson 138 kV 06/01/07 - $16,397,600 Project no longer being constructed

AEP is planning to build a new 1590 ACSR,138 kV line, approximately 7 miles long,that will be radial (at least initially) fromAEP's existing Hart's Island station inShreveport, Louisiana. The line will feed anew 138-12.5 kV station called "Port Robs

To provide a second feed to new loads. The new loads are expected to increase beyondthe level that the 69 kV system will be able to serve for single contingencies including:Overload of South Shreveport-Forbing 'T' 69 kV and Ellerbe Road-Lucas 69 kV for lossof Wallace Lake-Robson Road 69 kV or the Wallace Lake 138-69 kV autotransformer oroverload of Wallace Lake-Robson Road 69 kV for loss of South Shreveport-Forbing 'T'69 kV.

EMDE Line - ReinMiller - Tipton Ford 161 kV 06/01/07 - $3,215,000 Identified in the 2004_2005 SPP Expansion Plan as needed in 6/1/2007 TPL002

Install new 161 kV line from Sub 292 to Sub393 -- Build 4.2 miles Terminals at bothSubs

To address Joplin transformer overload for loss of Tipton-Joplin line

GRDA XFR - Stilwell City 161/69 kV 06/01/07 - $1,800,000 TO Study - NERC TPL-002 Install 161/69kV autotransformer at StilwellVoltage @ Stilwell 54521 drops to 0.90pu with loss of line 96986--96983. This area hasmultiple contingencies that create voltage violations according to NERC standards. ThisXfmr mitigates these violations.

KCPL Line - Tomahawk - Bendix 161 kV 12/01/06 - $528,600 Identified in the 2004_2005 SPP Expansion Plan as needed in 2006 - TPL-002 Rreconductor line with 1192 acsr Reliability project to eliminate thermal violations for contingencies SPP 2005 NERC

1A Reliability Assessments, contingency KCPL CROW #10, LaCygne-West Gardner

KCPL Device - South Waverly 161 kV 06/01/07 - $611,000 Identified in the 2004_2005 SPP Expansion Plan as needed in 6/1/2007 TPL002

Install 15 Mvar capacitor at S. Waverly 161 kV bus.

This is a new capacitor (15 Mvar) to solve the low voltages due to the outage of theNorton to Malta Bend 161 kV line. The cost is estimated by KCPL.

KCPL Line - Stilwell - Antioch 161 kV 06/01/07 - $892,600 Identified in the 2004_2005 SPP Expansion Plan as needed in 6/1/2007 - TPL-002 Reconductor 161kV line Reliability project to eliminate thermal violations for LaCygne-West Gardner contingency

KCPL 2005 Summer Peak Operating Studies, KCPL 2005 Transmission Expansion Plan

MIPU Line - Craig Interconnection 161 kV 06/01/06 - $75,000 TO Study - NERC TPL-002 New interconnection with AECI at Craig 69kV

This interconnection operated normal open, used as an emergency back up for SJLP69kV loop. Loss of Browns Curve - Midway 69kV line produces low voltage at Craig andother adjacent substations (0.771 pu)

MIPU Line - Nevada 161 - Nevada Plant 69 kV 10/01/06 - $536,000 TO Study - NERC TPL-002New Nevada Configuration - Appleton Citynow terminates in Nevada 161/69, newdouble circuit down to Nevada Plant

Loss of 69kV line from Nevada 161 sub to Metz causes overload (107% Loading)

OKGE Line - Reno - Sunny Lane 69 kV 06/01/06 - $100,000 Identified in the 2004_2005 SPP Expansion Plan as needed in 6/1/2006 TPL002

Replace Wave Trap and CT -- new limit1200A Reno - Sunny Lane overload for OKGEMTL-19 Contingency

OKGE Line - Richards Tap - Richards 138 kV 06/01/06 - $1,000,000 Violations of OGE Operating Practice S3-5 New 138 kV line Violations of OGE Operating Practice S3-5 due to radial load at Piedmont. S3-5documentation has been submitted to SPP in the past

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Base Plan List as of April 25, 2006

OKGE Line - Van Buren AVEC - VBI 69 kV 06/01/06 - $50,000 TO Study - NERC TPL-002 Trap & CTR work increase to 1200A. Single contingency 55294 JOHNSON to 55295 EXPOPRK 69kV in the 2007 SummerPeak model causes this overload. Violates NERC TPL-002-0 and SPP Criteria 3.4.

OKGE Line - Richards - Piedmont 138 kV 06/30/07 - $3,800,000 Violations of OGE Operating Practice S3-5 New 138kV line from Piedmont to Richards. Violations of OGE Operating Practice S3-5 due to radial load at Piedmont. S3-5documentation has been submitted to SPP in the past

SWPA XFR - Norfork 161/69 kV 06/01/07 - $1,300,000SWPA is not a current tariff signature, but would liketo participate in Cost Allocation under someagreement

Replace transformer with rebuilt 37 MVAXF To address Northfork transformer overload for outage of Northfork - Viola 69 kV

SWPS XFR - Bailey Co 115/69 kV 06/01/06 - $2,200,000 Identified in the 2004_2005 SPP Expansion Plan as needed in 2006 TPL002 Upgrade both existing transformer To address loss of parallel transformer

SWPS XFR - Denver City 115/69 kV 06/01/06 - $2,200,000 Identified in the 2004_2005 SPP Expansion Plan as needed in 2006 TPL002 Upgrade both existing transformer To address loss of parallel transformer

SWPS XFR - Kress 115/69 kV 06/01/06 06/01/07 $1,250,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/07 TPL002 Upgrade #2 Transformer To address loss of parallel transformer

SWPS XFR - Hockley 115/69 kV 12/01/06 - $2,750,000 Identified in the 2004_2005 SPP Expansion Plan as needed in 2006 TPL002 Upgrade both existing transformer To address loss of parallel transformer

SWPS XFR - Terry Co 115/69 kV 06/01/07 - $2,375,000 Identified in the 2004_2005 SPP Expansion Plan as needed in 2007 TPL002 Upgrade both existing transformer To address loss of parallel transformer

SWPS XFR - Hale Co 115/69 kV 12/01/07 - $2,900,000 Identified in the 2004_2005 SPP Expansion Plan as needed in 2007 TPL002 Upgrade both existing transformer To address loss of parallel transformer

WERE Line - Circle - Hutchinson Energy Center 115 kV 04/01/06 - $300,000 TO Study Identified as Needed June 2006

Tear down / Rebuild 0.40-mile linereplacing 556.5 kcmil ACSR with 1192.5kcmil ACSR; Project is part of a long rangeplan to correct service issues in the City ofHutchinson area

Overload for loss of Circle-Davis 115 kV line, NERC Reliability Standard TPL-002-0

WERE Line - Midwest Solvent Jct 1 - Atchison Jct 2 69 kV 05/18/06 - $35,000 TO Study Identified as Needed June 2006 Rebuild NERC Relibility Standard TPL-002-0 _Westar 06-10 Trans Const. Rec. P12

WERE Multi - Morris - McDowell 230 kV 07/19/06 - $7,224,000 TO Study Identified as Needed June 2006

Convert Morris County - McDowell Creekline to 230 kV operation; ConstructMcDowell Creek 230 kV substation andinstall 280 MVA 230-115 kV transformer;230 kV ring bus substation work required atMorris County.

See Westar Five-Year Transmission Construction Recommendations, August 12,2005,P. 8

WERE XFR - Butler 138/69 kV 08/01/06 - $1,600,000 TO Study Identified as Needed November 2006Transformer will now be installed at Butlersubstation instead of Midian See email fromDon Taylor 10/28/05

New load requires this transformer addition; Required for compliance with NERCReliability Standard TPL-002-0

WERE Device - Clearwater 138 kV 12/31/06 - $1,000,000 TO Study Identified as Needed Decemberr 2006 Install switched capacitor bank at the new Clearwater 138 kV substation

NERC Reliability Standard TPL-002-0 - See Westar Energy Five-Year TransmissionConstruction Recommendations, August 12,2005, P. 15

WERE Device - UDALL 2 69 kV 12/31/06 - $525,000 TO Study Identified as Needed Decemberr 2006 Install switched capacitor bank NERC Reliability Standard TPL-002-0_Westar 5y_Trans_Const_Recomendation 2006-2010 p15-16

WERE Multi - HEC - 43rd & Lorraine - Tower 33 69 kV 12/31/06 - $2,400,000 TO Study Identified as Needed December 2006Tear down / rebuild 5.20-mile 69 kV line as115 kV. 69 kV system in Hutchinson will beconverted to 115 kV by fall 2008.

Required for compliance with NERC Reliability Standard TPL-002-0. The projecteliminates Transmission Operating Directives when the conversion to 115 kV iscomplete in fall 2008. This construction and rebuilding of substations are interlinked toprovide

WERE Device - NE Parsons 138 kV 06/01/07 06/01/07 $1,000,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007 TPL002 Install switched capacitor bank NERC Reliability Standard TPL-002-0_Westar 5y_Trans_Const_Recomendation 2006-

2010 p14

WERE Device - Parsons 69 kV 07/01/07 06/01/07 $525,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007 TPL002 Install switched capacitor bank NERC Reliability Standard TPL-002-0 _Westar 5y_Trans_Const_Recomendation 2006-

2010 p13

WERE Device - Nortonville 69 kV Cap - 06/01/07 $564,000 Identified in the 2006 SPP Expansion Plan as needed in 6/1/2007 TPL002

Install 15 Mvar cap at Nortonville 69 kV (bus #57481)

NERC Reliability Standard TPL-002-0_Westar 5y_Trans_Const_Recomendation 2006-2010 p18

WERE XFR - Weaver 138/69 kV 07/01/10 07/01/10 $1,200,000 Project pushed back to 2010 for reliability need New transformer #2 at Weaver To address ineffective operating guide in 2010

WFEC Device - Dover - 06/01/15 $90,000 Project is being replaced by Rush Springs Cap Add 3 MVAR switched capacitor at RushSprings 69 kV bus. Low Voltage around Dover for loss of Dover XF

Total: $51,832,425 Note: Totals do not included projects that have been removed

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Southwest Power Pool, Inc. MARKETS AND OPERATIONS POLICY COMMITTEE

Recommendation to the Board of Directors On Attachment J Waiver Requests

January 30, 2007

Organizational Roster The following members represent the Southwest Power Pool Staff:

Leslie E. Dillahunty, Vice President, Regulatory Policy

Patrick Bourne, Director, Transmission Policy

Jay Caspary, Director, Engineering

John Mills, Manager, Tariff Studies

Heather Starnes, Attorney

Background Attachment J of the SPP Tariff addresses recovery of costs associated with new transmission facilities. Subsection III of this section addresses Base Plan funding for network upgrades, including the Safe Harbor Cost Limit of $180,000/MW, and provides for waivers, whereby application may be made for additional Base Plan funding for a network upgrade in excess of the Safe Harbor Cost Limit based on three independent factors.

On October 13, 2006, SPP received a request for waiver under Attachment J of the SPP Tariff for costs in excess of the Safe Harbor Cost Limit for Base Plan Funding for the Rose Hill-Sooner 345 kV project of Westar. SPP’s 120-day deadline under Attachment J is February 10, 2007.

Analysis Westar’s requested a waiver based upon Section III.C.2.ii of Attachment J and a reservation of 20 years. While other alternatives to this project were considered, their benefits proved to be local and short-term in nature. Westar and SPP staff agree that the regional and long-term benefits offered by this project, the increase in wholesale competition resulting from this project, and the commitment by OG&E, PSO and OMPA to build the largest coal-fired generating unit, Red Rock, adjacent to the Sooner station justify full Base Plan funding for the entire project. Recommendation The recommendation of SPP staff is to provide a waiver of such extent that this project is fully Base Plan funded.

Approved: Approved by MOPC on 01/26/07 with six abstentions (OMPA, Redbud, ETEC, KCPL, TEXLA, Lafayette Utilities)

Action Requested: Approval by Board of Directors

Attachment: Westar Waiver Letter, CAWG Recommendation to MOPC

Southwest Power Pool, Inc. COST ALLOCATION WORKING GROUP

Recommendation to the Markets and Operations Policy Committee On Attachment J Waiver Requests

January 26, 2007

During the CAWG meeting January 24, 2007 Jay Caspary, SPP staff, presented an overview of the Westar waiver. Discussion preceded the unanimous vote of support for the waiver by the five RSC states, present or participating in the discussion. The CAWG recommends to the MOPC that the Westar waiver associated with Transmission Service Request, reservation 1086655 designated as the Spring Creek 225 MW DNR to increase the Base Plan funding required by building the Rose Hill – Sooner 345 kV upgrade from $40,500,000 to an estimated engineering and construction amount of $54,788,600 be approved.

Southwest Power Pool Markets and Operations Policy Committee Recommendation to the Board of Directors

January 30, 2007

The CAWG recommends to the MOPC that the OG&E, Transmission Service Request, reservation 1032973 designated as Centennial Wind Farm with a waiver amount recommended by the SPP staff of $747,000, be approved. The CAWG specifically does not adopt the assumptions and analysis specifics employed by SPP staff in reaching their conclusion to recommend the waiver amount of $747,000. However, the CAWG did confirm through its own review and analysis the reasonableness of the amount recommended by the SPP staff. Approved: Markets and Operations Policy

Committee January 17, 2007

Approved with One Abstention-Kansas City Power & Light

Action Requested: Approval of OG&E Transmission Service Request, Reservation 1032973, in the amount of $747,000.

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Southwest Power Pool Regional State Committee & Board of Directors/Members Committee

Future Meeting Dates & Locations

2007

RSC/BOD April 23-24 Oklahoma City *BOD June 11-12 Little Rock RSC/BOD July 23-24 Kansas City

RSC/BOD October 29-30 Tulsa (Annual Meeting of Members) **BOD December 11 Dallas

2008

RSC/BOD January 28-29 New Orleans

RSC/BOD April 21-22 Oklahoma City

*BOD June 9-10 Little Rock

RSC/BOD July 28-29 Kansas City

RSC/BOD October 27-28 Tulsa (Annual Meeting of Members)

**BOD December 9 Dallas

The RSC/BOD meetings are Mon/Tues with the RSC held on Monday afternoon and the BOD/Members Committee meeting on Tuesday. * The June BOD meetings are for educational purposes. There will be no RSC meeting in conjunction with these meetings. ** The December BOD meetings are intended to be one day in and out meetings for administrative purposes. There will be no RSC meeting in conjunction with these meetings.

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