Southwest Power Pool BOARD OF DIRECTORS/MEMBERS … · Mr. Jackson reported that SPP requested Mr. Craig Westbrook, outside legal counsel for the SPP Pension and 401(k) Plans, draft

Southwest Power Pool BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING

Inn and Spa at Loretto - Santa Fe, NM October 25, 2005

- Summary of Action Items -

1. Approved minutes of the July 26, 2005 Board of Director/Members Committee meetings.

2. Approved the Compliance Committee’s recommendation to approve an SPP process for appeals.

3. Approved the Finance Committee’s recommendation to amend the previously approved Credit Policy to include language concerning calculation of potential exposure.

4. Approved the Finance Committee’s recommended 2006 Budget.

5. Approved the Finance Committee’s recommendation to establish an assessment and tariff Schedule 1

rate of $0.16MWh effective January 1, 2006.

6. Approved the Human Resources Committee’s recommendation of the employee Performance Compensation Plan becoming effective for SPP’s 2005 fiscal year.

7. Approved Human Resources Committee’s recommendation to terminate SPP’s policy of crediting new

employees’ years of service with SPP member companies effective November 1, 2005.

8. Approved the Markets and Operations Policy Committee’s recommended revisions to Criteria 9 made in light of NERC Version 0 Standards.

MINUTES NO. 101


Inn and Spa at Loretto - Santa Fe, NM October 25, 2005

Agenda Item 1 - Administrative Items SPP Chair Mr. Jim Eckelberger called the meeting to order at 9:50 a.m. immediately following the Annual Meeting of Members (Agenda – Attachment 1). 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. David Christiano, City Utilities of Springfield, MO Mr. Harry Dawson, Oklahoma Municipal Power Authority Mr. Mel Perkins, for Mr. Michael Desselle, American Electric Power Mr. Jim Eckelberger, director

Ms. Trudy Harper, Tenaska Power Services Company Mr. Doug Henry, Westar

Mr. Quentin Jackson, director Mr. Joshua Martin, director Mr. Mike Palmer, Empire District Electric Company Mr. Steve Parr, Kansas Electric Power Cooperative Mr. Gary Roulet, Western Farmers Electric Cooperative Mr. Harry Skilton, director Mr. Richard Spring, Kansas City Power & Light Mr. Jim Stanton, Calpine Mr. David Brian, for Mr. Rick Tyler, Northeast Texas Electric Cooperative Mr. Ricky Bittle, for Mr. Gary Voigt, Arkansas Electric Cooperative Corporation

Mr. Walt Yeager, Cinergy Corporation There were 55 persons in attendance either in person or via phone representing 27 members (Attendance List - Attachment 2). Mr. Carl Monroe reported proxies and a quorum was declared (Proxies - Attachment 3). Mr. Eckelberger asked for a round of introductions. Mr. Eckelberger referred to draft minutes of the July 26 meeting and asked for corrections or a motion for approval (7/26/05 Meeting Minutes - Attachment 4). Mr. Martin moved that the minutes be approved as presented. Mr. Jackson seconded the motion, which passed. Agenda Item 2 – Regional State Committee Report RSC President, Denise Bode presented the Regional State Committee (RSC) report. Commissioner Bode reported that Mr. Tom Kraemer of BNSF addressed the RSC prior to yesterday’s meeting concerning the Powder River Basin, track repairs, and the future of coal delivery. High coal prices are expected. Commissioner Bode stated that the RSC Bylaws were revised to provide flexibility of officer’s terms. An election was held with the results being:

President – Denise Bode Vice President – Julie Parsley Treasurer – Brian Moline

Secretarial duties – SPP with Les Dillahunty as Staff contact to be supervised by Vice President Parsley

SPP Board of Directors/Members Committee Minutes October 25, 2005

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Updates were given on FERC activities by Tony Ingram and Cyndy Marlette and on SPP activities by Carl Monroe. Ms. Bode announced that RSC was well under budget for 2005 and had approved budgets for 2006 and 2007 totaling $448,530. RSC approved the Cost Allocation Working Group proposal for the LGIA base plan and aggregate study. Concerning the FERC decision on confidential data, RSC plans to move forward with the SPP view. The next scheduled RSC meeting is in Dallas on January 30, 2006. Agenda Item 3 – Compliance Committee Report Mr. Josh Martin presented the Compliance Committee Report (CC Report – Attachment 5). The Compliance Committee last met on September 28, 2005. Mr. Martin’s review of activities included:

• NERC Audit and compliance field review • Update from the Market Monitoring Unit (MMU) and the Independent Market Monitor (IMM) • Approval of a 2006 budget for the Compliance Department • Drafting of an investigation process • Modified the 2006 budget for Boston Pacific activities

The Compliance Committee is charged with hearing appeals from members related to findings by the Compliance Department of SPP. A recent appeal necessitated the development of an appeal process. Mr. Martin moved the following recommendation:

The Compliance Committee recommends approval of this process for appeals heard by the Committee. The Committee also recommends that the Board direct the Markets and Operations Policy Committee and its working groups to implement an appeals process, which may be the same.

Mr. Quentin Jackson seconded the motion. The Members were unanimous in favor. The motion passed. Mr. Martin introduced Craig Roach of Boston Pacific to provide an update on the IMM activities. Mr. Roach stated that the Redbud inquiry will be made public. FERC rejected the filing of tariff language for the Market and gave guidance. The IMM filed a request for clarification as did SPP concerning the market based rates and cost based rates. In the initial assessment, the RTO Order set rules for the IMM. The IMM has crafted a draft of the remaining rules and requests feedback through email, through SPP Staff, or through the stakeholder process. The final IMM report will be submitted to the Board of Directors in January. Agenda Item 4 – Finance Committee Report Mr. Harry Skilton presented the Finance Committee report. Mr. Skilton addressed the SAS-70 Readiness Assessment, D&O liability and insurance, the SPP credit policy, the 2006 Budget and future financing. Mr. Skilton commended the Credit Task Force (CTF) for a job well done. Tom Dunn was asked to present the CTF recommendation (Credit Policy Recommendation - Attachment 6). Mr. Dunn explained that the previously approved Credit Policy was amended to include a new methodology for calculation of potential exposure to services sold through the regional tariff. Mr. Skilton moved to approve the following recommendation:

The Finance Committee recommends the Credit Policy previously approved by the SPP Board of Directors at its April 25, 2005 meeting be amended to include the attached language concerning calculation of potential exposure. The Finance Committee further recommends the Credit Policy be filed separate from the EIS filings to allow for a request for expedited review. Additionally, the Finance Committee recommends implementation of the Credit Policy be delayed until FERC completes its review and action on the Credit Policy filing.


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Mr. Eckelberger seconded the motion. The Members were unanimous in favor. The motion passed. Mr. Dunn provided background on the 2006 SPP Budget (2006 Budget Report and Recommendation – Attachment 7). He reviewed the operating budget, capital expenditures, and administrative fees. Carl Monroe pointed out that some items are not included in the budget: Integrated Resource Planning, Ancillary Service Market’s Cost Benefit analysis, and cyber security needs. The new facility was discussed. Doug Henry urged that a project manager be named for the new facility or a third party hired. A report with final figures on the new facility will be presented to the Board in December. Mr. Skilton moved to approve the 2006 Budget. Mr. Martin seconded the motion. The Members were unanimous in favor. The motion passed. Mr. Skilton provided background regarding the assessment and Tariff Schedule 1 rate for 2006 (Rate Recommendation – Attachment 8). SPP is projecting a surplus for 2006 and 2007. The question raised is whether SPP should maintain its administrative fee rate at $0.16MWh in order to build a surplus for future expenditures. Mr. Skilton moved to approve the Finance Committee recommendation:

The Finance Committee recommends the SPP Board of Directors establish an assessment and tariff schedule 1 rate of $0.16MWh effective January 1, 2006.

Mr. Martin seconded the motion. The Members were unanimous in favor. The motion passed. Mr. Mel Perkins suggested backing –up the SPP budget process in order to help member companies as they undergo their budget processes. Mr. Skilton said this would be discussed at the December Board meeting. Mr. Skilton explained there will be a need to arrange financing in 2006 to cover capital expenditures. Initial inquiries will be started and a financing plan will be presented to the Board in the first quarter. Agenda Item 5 – Human Resources Committee Report Mr. Quentin Jackson provided a Human Resources Committee (HRC) report. Mr. Jackson reported that the HRC met on Monday, October 24, with full attendance. Topics discussed were: SPP training and development plan, compensation, the 360° evaluation plan, and committee effectiveness. Mr. Jackson recognized Malinda Stevens as doing a commendable job especially given that the SPP Human Resources Department is made up of only two people. Mr. Jackson provided background on the Employee Performance Compensation Plan (Compensation Plan – Attachment 9). This plan is measured against SPP’s foundation budget, customer satisfaction, and reliability and is to provide incentive for employees to ensure SPP remains competitive in attracting and retaining qualified personnel. The Performance Compensation pool is expected to average approximately 15% of SPP’s year end annualized salaries. Funding targets for the 2005 plan year will be set at 50% of the targets outlined in the document in recognition of the late year roll-out of the plan. Mr. Jackson moved to approve the following recommendation:

The Human Resources Committee recommends approval of the employee Performance Compensation Plan by the SPP Board of Directors with the plan becoming effective for SPP’s 2005 fiscal year.

Ms. Bernard seconded the motion. The Members were in favor with abstentions from Mr. Harry Dawson and Mr. Ricky Bittle. The motion passed. Mr. Jackson reported that SPP requested Mr. Craig Westbrook, outside legal counsel for the SPP Pension and 401(k) Plans, draft amendments to rescind the granting of years of service credit with member companies (Years of service – Attachment 10). Mr. Jackson moved to approve the following recommendation:

Terminate SPP’s policy and practice of crediting new employees with years of service with SPP member companies effective November 1, 2005. Employees hired after October 31, 2005 will no longer receive credit for years of service. Adopt amendments to SPP’s retirement plans effective November 1, 2005


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defining years of service for employees hired after October 31, 2005 as only that time employed by SPP. Direct SPP staff to amend its vacation policy to define years of service for employees hired after October 31, 2005 as only that time employed by SPP.

Mr. Skilton seconded the motion. The Members were in favor with one opposing vote by Mr. Jim Stanton. The motion passed. Mr. Jackson announced that SPP had been recognized by Principal Financial, SPP’s 401K provider, as one of the top ten companies that excel in providing financial security to its workers through wellness programs, health education and retirement savings. SPP was selected from a pool of 500 nominees and rewarded a check in the amount of $2,500 donated in SPP’s name to United Way. Agenda Item 6 – Strategic Planning Committee Report Mr. Richard Spring presented the Strategic Planning Committee Report (SPC Report– Attachment 11). Mr. Spring reviewed topics the committee has discussed since his last report to the Board. Mr. Spring also reviewed the organizational group assessment process. The organizational group assessment will be reviewed and a presentation will be made to the MOPC and then to the Board of Directors/ Members Committee. Mr. Spring provided background on recommended SPP Bylaws revisions regarding the waiver of annual membership fees (Bylaws Revisions – Attachment 12). This serves as the required 30 days notice for review and will be submitted for approval at the December Board meeting.

Agenda Item 7 – Markets and Operations Policy Committee Report Mr. Mel Perkins presented the Markets and Operations Policy Committee Report (MOPC) (MOPC Report and Recommendation – Attachment 13). Mr. Perkins began his report by thanking Dave Christiano for all of his past work in SPP. Mr. Christiano started working with SPP in 1978 and will retire at the end of 2005. Mr. Perkins reviewed background regarding proposed revisions to Criteria 9 made in light of NERC Version O Standards. Mr. Jackson moved to approve Criteria 9 revisions. Mr. Altenbaumer seconded the motion. The Members were in unanimous favor. The motion passed. Mr. Perkins then provided MOPC information items:

• MOPC approved 18 PRRs - PRRs provide direction to the RTWG for development of Tariff language. • Market participant readiness – MOPC held a roundtable discussion. Most Market Participants (MP)

are working on various levels of testing, development, training and developing contractual arrangements. No MP thought the May 1, 2006 date could not be supported.

• Implications of potential market delay – MOPC approved a recommendation from the ORWG that if the EIS Market is delayed beyond the May 1 start date, implementation should not be scheduled during the June 1 – September 30, 2006 period.

• Formation of MOTRTF – Market Operations Tools Readiness Task Force formed to ensure readiness of tools, systems, and data required for the EIS Market.

• Market Tariff filing – MOPC is to meet on November 30 to review and approve tariff changes necessary to support the EIS Market.

• Expansion Plan – Due to various concerns, the MOPC did not approve Phase II of the SPP Transmission Expansion Plan. Concerns will be addressed at the CAWG workshop on November 10.

Tom Dunn provided a report from Accenture regarding the Market Readiness Assessment (Market Scorecard – Attachment 14). Currently a metrics framework is being developed to assess readiness. It is planned to submit these metrics for approval at the next MOPC meeting.


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Agenda Item 8 – Future Meetings The next Board of Directors/Members Committee meeting is December 6 in Dallas. Mr. Eckelberger explained that moving forward the process of voting for motions would be: if you would like to amend a motion, it must first be voted down and then an amended motion be presented for approval. The Board can also send issues back to committee. Mr. Skilton stated that if an action item is returned to committee both majority and minority opinions as well as Staff opinions should accompany the new recommendation. Mr. Eckelberger complimented Carl Monroe for his job as Nick Brown’s replacement while Mr. Brown has been on leave of absence attending the Harvard Advanced Management Program. Mr. Eckelberger recognized Mr. Dave Christiano for his years of service with SPP, which received a standing ovation. Mr. Eckelberger also recognized Cyndy Marlette (FERC) and thanked her for her attendance. Both Mr. Christiano and Ms. Marlette were given the opportunity to make remarks. Adjournment With no further business, Mr. Eckelberger thanked everyone for participating and adjourned the meeting at 12:55 p.m. Stacy Duckett, Corporate Secretary

BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING

and ANNUAL MEETING OF MEMBERS October 25, 2005

Inn and Spa at Loretto – Santa Fe, NM

• A G E N D A • 8:00 a.m. – 2:30 p.m. MST *

Annual Meeting of Members 1. Administrative Items .................................................................................................Mr. Jim Eckelberger

2. Corporate Governance Committee Report..................................................................Ms. Stacy Duckett

a. Election of Directors

b. Election of Members Committee Representatives

c. Board of Directors Annual Evaluation

3. Organizational Reports – 2005 Overview/2006 Outlook

a. Operations...................................................................................................Mr. Carl Monroe

b. Finance ..........................................................................................................Mr. Tom Dunn

c. Corporate .................................................................................................Ms. Stacy Duckett

d. Regulatory................................................................................................ Mr. Les Dillahunty

e. Interregional Affairs .................................................................................Mr. Charles Yeung

Adjourn for Board of Directors/Members Committee Meeting

Board of Directors/Members Committee Meeting 1. Administrative Items ................................................................................................ Mr. Jim Eckelberger

2. Regional State Committee Report.................................................................................Ms. Denise Bode

3. Compliance Committee Report ....................................................................................... Mr. Josh Martin

a. Independent Market Monitor Report ...........................................................Mr. Craig Roach

4. Finance Committee Report............................................................................................ Mr. Harry Skilton

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

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

7. Markets and Operations Policy Committee Report .........................................................Mr. Mel Perkins

8. Future Meetings........................................................................................................Mr. Jim Eckelberger

* The meeting times are local to the meeting site. If you are dialing in, please plan accordingly.


Doubletree at Warren Place – Tulsa, OK July 26, 2005

- Summary of Action Items -

1. Approved minutes of the April 26 and June 10, 2005 Board of Director/Members Committee meetings.

2. Approved the Human Resources Committee’s recommendation of funding of the SPP Retirement Plan at $979,000 and the SPP Post-retirement Benefits Plan at $471.200 but amended the amounts to $1,075,791 and $504,000 respectively.

3. Approved the Human Resources Committee’s recommendation to provide a supplemental executive

retirement plan (SERP) compliant with section 457(b) of the Internal Revenue Code.

4. Approved the Markets and Operations Policy Committee recommendation to implement the Energy Imbalance Service Market May 1, 2006.

5. Approved an amended Markets and Operations Policy Committee’s regional transmission definition:

All existing non-radial power lines, substations, and associated facilities, operated at 60 kV or above, plus all radial lines and associated facilities operated at or above 60 kV that serve two or more eligible customers not Affiliates of each other. All facilities operated at 60 kV and above constructed in the future would be included.

6. Approved Markets and Operations Policy Committee’s recommendation for Tariff modifications to: Schedule 1, Attachment L, and Attachment AA necessary to specify an “unpancaked” scheduling charge and provide for the distribution of revenue between multiple entities owning transmission facilities in a single zone.

7. Approved the Strategic Planning Committee’s recommendation to adopt the Strategic Plan 2005 and

authorize the delegation of responsibilities to SPP organizational groups under the coordination oversight of the Strategic Planning Committee and the Markets and Operations Committee to carry out the plan.

9. Approved the Strategic Planning Committee’s recommendation to approve the necessary SPP Bylaws and

Membership Agreement amendments to waive the withdrawal obligation related to long-term commitments and future interest for large retail customer Members, small retail customer Members, and alternative power/public interest Members so long as the entity is not a market participant

10. Approved the Entergy ICT Business Plan Proposal and granted the authority to execute the documents

necessary to develop this project.

11. Approved the Corporate Governance Committee’s nomination of Larry Altenbaumer to replace Bob Schoenberger on the Finance Committee.

12. Approved the Finance Committee’s recommendation increasing the 2005 capital budget to $18.3M from

the previously approved level of $12.8M.

MINUTES NO. 100


Doubletree at Warren Place, Tulsa, OK July 26, 2005

Agenda Item 1 - Administrative Items SPP Chair Mr. Jim Eckelberger called the meeting to order immediately following a Special Meeting of Members (Agenda – Attachment 1). 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, Southwest Power Pool Mr. David Christiano, City Utilities of Springfield, MO Mr. Harry Dawson, Oklahoma Municipal Power Authority Mr. Michael Desselle, American Electric Power Mr. Jim Eckelberger, director

Mr. Kevin Easley, Grand River Dam Authority Ms. Trudy Harper, Tenaska Power Services Company Mr. Doug Henry, Westar

Mr. Quentin Jackson, director Mr. Joshua Martin, director Mr. Mike Palmer, Empire District Electric Company Mr. Steve Parr, Kansas Electric Power Cooperative Mr. Gary Roulet, Western Farmers Electric Cooperative Mr. Harry Skilton, director Mr. Richard Spring, Kansas City Power & Light Mr. Jim Stanton, Calpine Mr. David Brian, for Mr. Rick Tyler, Northeast Texas Electric Cooperative Mr. Gary Voigt, Arkansas Electric Cooperative Corporation

Mr. Bill Jett, for Mr. Walt Yeager, Cinergy Corporation There were 47 persons in attendance representing 26 members (Attendance List - Attachment 2). Mr. Brown reported proxies and a quorum was declared (Proxies - Attachment 3). Mr. Eckelberger asked for a round of introductions. Mr. Eckelberger referred to draft minutes of the April 26 and June 10, 2005 meetings and the asked for corrections or a motion for approval (4/26/05, 6/10/05 Meeting Minutes - Attachment 4). Ms. Bernard moved that the minutes be approved as presented. Mr. Skilton seconded the motion, which passed. Agenda Item 2 – President’s Report Mr. Nick Brown presented the President’s Report (Quarterly Report – Attachment 5). Mr. Brown highlighted several items in the Quarterly Report including the rise in TLR events over last year. He stated that the number of TLRs is being evaluated to see what is influenced by the market implementation. Ms. Harper requested that information be sent via email regarding how many TLRs were called by Southwest Power Pool versus other reliability coordinators. In addition to the Quarterly Report, Mr. Brown provided updates on administration, regulatory, operations and interregional issues (President’s Report to BOD – Attachment 6). The administration items noted were:

• SPP Staff currently includes 145 full time employees, 1 intern and one part-time employee. Additional

SPP Board of Directors/Members Committee Minutes July 26, 2005

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year-to-date statistics were given. • Architectural drawings for the new operations center were on display for review. It is expected to be

operational prior to summer 2006. • Energy imbalance service market training is organized into four training tracks including Markets for IT,

Operations/Trading, Scheduling, and Settlements. The training department has conducted market training classes for approximately 350 people since January of 2005.

• Mr. Brown announced that with the Board’s encouragement he applied and has been accepted to Harvard Business School’s Advanced Management Program. The program runs September 11 - November 4, 2005. Carl Monroe and the SPP officers will be responsible for SPP during that time.

Regulatory items reviewed:

• Commissioner Joseph Kelliher was appointed chairman of FERC replacing Pat Wood. Chairman Kelliher appointed Dan Larcamp as Commission Chief of Staff and Shelton Canon to head the Office of Markets Tariffs and Rates.

• Comments and protests to SPP’s energy imbalance market tariff filing were due July 15th. It is hopeful an order will come in early September.

Operations items:

• Implementation of the MISO JOA is proceeding on schedule for an October 1, 2005 implementation of coordination on flowgates.

• The SPP Reliability Coordinator had a Readiness Audit conducted by NERC. • The transmission facilities of Aquila’s three operating companies, Missouri Public Service Co., St. Joseph

Light & Power and West Plains Energy, were added to the SPP regional tariff July 1. • Staff is working on the first ever Aggregate System Impact Study. They are on tract for achieving a study

publication in the first week of August. Interregional Issues:

• COMPETE, a national coalition promoting the public interest benefits of competitive electricity markets, released a new study last week showing considerable consumer savings from 1999 – 2003 stemming from wholesale electric market competition.

• The ISO/RTO Council is nearing completion of a white paper detailing the benefits of regional transmission organizations.

Agenda Item 3 – Regional State Committee Report RSC President, Denise Bode presented the Regional State Committee (RSC) report via phone. Commissioner Bode stated that the RSC has filed comments on the long-term transmission rights signed by all states with the exception of Texas. There was an RSC conference call on July 7 at which Mike Proctor reviewed the transmission definition. The consensus of the RSC was that of support. Ms. Bode added that the RSC would discuss the following items at their meeting July 27: large generation interconnection agreements; status of the cost benefit study; the energy imbalance market; a presentation on confidentiality and its issues and impacts on the RSC; the RSC budget; and the RSC audit arranged for by Commissioner Sandy Hochstetter. Commissioner Bode requested that in the future, hard copies of the Board of Director’s background material be distributed to the RSC. Agenda Item 4 – Finance Committee Report Mr. Harry Skilton presented the Finance Committee report. Mr. Skilton stated that the next Finance Committee meeting is to be held on August 11 in Dallas. The agenda will include the directors and officers insurance and a discussion of, the SAS70 Audit with Price Waterhouse. The committee is resolved to file the credit policy with the October filing.


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Mr. Skilton reported that the Credit Task Force is gathering credit profiles from the members and customers. Every member and customer will be scored. It is the goal to have all scoring completed and the results communicated to all profiled by August 31, 2005. The results will be posted on the OASIS site. Ms. Harper requested that filing of the Credit Policy be held off as long as possible. Mr. Tom Dunn stated that the Credit Policy will be filed in October with the EIS Market Tariff changes. Agenda Item 5 – Human Resources Committee Report Mr. Quentin Jackson provided a Human Resources Committee (HRC) report. Mr. Jackson stated that the committee met on Monday, July 25. Discussion included a review of the SPP benefit plan and the employee compensation plan. The committee decided that a 4% cost of living raise would be applied to SPP employees in 2006. The committee also is outlining an incentive compensation plan in which all employees may participate. Details of this plan will be presented at the October Board of Directors meeting. Mr. Jackson provided background on the SPP Retirement Plan and the SPP Post-Retirement Plan (Retirement Plan Recommendation – Attachment 7). Mr. Jackson moved that the Board of Directors: Approve 2005 funding of the SPP Retirement Plan at $979,000. Approve 2005 funding of the SPP Post-retirement Benefits Plan at $471,200. Mr. Altenbaumer seconded the motion. Mr. Skilton moved to amend the recommendation to contribute the maximum level of $1,075,791 and $504,000 while possible. Ms. Bernard seconded the amendment. The Members were unanimous in favor. The motion passed. A vote was called for the amended motion. The Members were unanimous in favor. The motion passed. Mr. Jackson provided background on the supplemental executive retirement plan (SERP Recommendation and Plan Document – Attachment 8). The HRC developed a draft SERP compliant with section 457(b) of the Internal Revenue Code. Mr. Jackson moved to approve the following recommendation:

The Human Resources Committee recommends SPP establish a supplemental executive retirement plan in substantially the form discussed above and detailed in the attached plan document.

Ms. Bernard seconded the motion. The Members were unanimous in favor. The motion passed. Agenda Item 6 – Markets and Operations Policy Committee Report Mr. Mel Perkins presented the Markets & Operations Policy Committee Report (MOPC Presentation – Attachment 9). Mr. Perkins provided an update on MOPC activities. Mr. Richard Ross then presented the Market Working Group (MWG) report (MWG Report – Attachment 10). Mr. Ross reviewed background for the market implementation and presented the following recommendation for Board approval: The MOPC supports the recommendation of the MWG to implement the EIS Market by May 1, 2006. Mr. Skilton moved to approve the May 1 date for market implementation. Ms. Bernard seconded the motion. The Members were unanimous in favor. The motion passed. Mr. Eckelberger stressed the need to make the May 1, 2006 deadline. Mr. Dennis Reed reviewed MOPC recommendations coming from the Regional Tariff Working Group including:


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1. Mr. Reed provided background for the transmission definition (Transmission Definition Recommendation – Attachment 11). The MOPC approved an amended transmission definition modifying Attachment AI, section II, paragraph 1 at their July 12 – 13 meeting to read: All non-radial power lines, substations, and associated facilities, operated at 60 kV or above, plus all radial lines and associated facilities operated at or above 60 kV that serve two or more eligible customers not Affiliates of each other.

Mr. Harry Dawson presented background and reasons for an amended definition omitting the last phrase:

All non-radial power lines, substations, and associated facilities, operated at 60 kV or above, plus all radial lines and associated facilities operated at or above 60 kV.

Mr. Skilton moved to approve the transmission definition as presented by MOPC with the modifications to Attachment AI, section II, paragraph 1. Mr. Jackson seconded the motion. During considerable discussion a third option was drafted with the following additions:

All existing non-radial power lines, substations, and associated facilities, operated at 60 kV or above, plus all radial lines and associated facilities operated at or above 60 kV that serve two or more eligible customers not Affiliates of each other. All facilities operated at 60kV and above constructed in the future would be included.

Mr. Eckelberger asked for a straw vote from the Members on each of the three drafts. The first draft as presented by MOPC received a vote of 5 for, 7 against, and 2 abstentions. The second draft from OMPA received a vote of 8 for, 4 against, and 2 abstentions. The third draft received a vote of 7 for, 6 against, and 1 abstention. Mr. Skilton and Mr. Jackson withdrew the original motion. Mr. Brown moved to approve draft number three stating that it was a good compromise of the first two drafts. Ms. Bernard seconded the motion. Mr. Eckelberger called for another Members vote on the third draft to see if any opinions had changed during discussion. A second Members vote for the third draft received 8 for and 6 against. The directors voted and the motion passed.

2. Mr. Reed provided background for Tariff modifications to: a) Schedule 1 and Attachment L implementing

the removal of pancaked scheduling fees; b) Attachment L reflecting allocation of money between Transmission Owners in the same zone; and c) continuation of the experimental Transmission Service Prepayment option for an additional year (Tariff Modifications – Attachment 12). Mr. Skilton moved to approve the Tariff modifications as presented. Mr. Altenbaumer seconded the motion. The Members were unanimous in favor. The motion passed

Agenda Item 7 – Compliance Committee Report Mr. Josh Martin presented the Compliance Committee Report (CC Report – Attachment 13). Mr. Martin stated that the committee met June 3. Committee activities included a review of the State of the Market Report filed at FERC; extension of the Boston Pacific’s contract through the end of 2005, which falls within the approved budget; and a NERC compliance update. Regarding NERC compliance, two member companies were cited for violations relating to a lack of NERC-certified operators. One company has resolved this matter and the other company expects to resolve this violation through attrition later this year. NERC has published the results of an SPP Readiness Audit performed in April 2005. Southwest Power Pool did well with positive observations. The next Compliance Committee meeting is September 28 in Chicago. Mr. Craig Roach provided an Independent Market Monitor report (IMM Report – Attachment 14). Mr. Roach stated that the 2004 State of the Market Report was filed May 31, 2005. Two testimonies were filed in support of the SPP EIS Market Tariff revisions on June 15, 2005. There were few protests with an overall constructive tone. The MO-KN-OK Agreement comments are at FERC.


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Agenda Item 8 – Strategic Planning Committee Report Mr. Richard Spring presented the Strategic Planning Committee Report (SPC Report– Attachment 15). Mr. Spring stated that the SPC held a planning retreat May 12-13, which was well attended with representatives from the RSC, FERC, DOE, and SPP independent board members. Another SPC meeting was held on July 14 discussing: fee waiver, Strategic Plan 2005, Entergy ICT, North Carolina LSE, regulatory updates, and organization effectiveness. Mr. Spring explained that two years ago the SPC developed a Strategic Plan, which was expected to take 5 years to implement. Approximately 95% of that plan has been achieved. The Strategic Plan 2005 has been drafted for 1 to 3 years into the future with a long-term plan to follow (Strategic Plan – Attachment 16). The Strategic Plan 2005 addresses: market development, transmission expansion, administrative processes, retention and addition of members, and enhanced regional planning. Mr. Spring made the following recommendation (Strategic Plan Recommendation – Attachment 17):

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 SPC and MOPC.

Mr. Skilton moved to approve the Strategic Plan 2005. Mr. Brown seconded the motion. The Members were unanimous in favor. The motion passed. Mr. Spring provided background on the fee waiver process as directed by FERC and presented the following SPC recommendation (Fee Waiver Recommendation – Attachment 18):

Approval of the Bylaws and Membership Agreement amendments as presented to waive those portions of the withdrawal obligation related to long-term commitments and future interest for large retail customer Members, small retail customer Members, and alternative power/public interest Members so long as the entity is not a market participant, effective July 26. Affirmation that the membership of entities with affiliate relationships as defined in the SPP Bylaws will be considered separate for purposes of eligibility for the fee waiver.

Mr. Altenbaumer moved to approve the fee waiver recommendation. Mr. Skilton seconded the motion. The Members were unanimous in favor. The motion passed. Agenda Item 9 – Entergy ICT Proposal Mr. Bruce Rew provided a report on the Entergy ICT Proposal (Entergy ICT Proposal- Attachment 19). In a FERC ICT declaratory order, it was assumed that SPP would be selected as the ICT for Entergy as SPP complies with the independence requirement. The primary functions would be:

• Reliability Coordinator • Tariff Administrator • Calculation of ARCs • Transmission Planning • Weekly Procurement Process

Mr. Rew presented an Entergy ICT Buisness Plan (Entergy ICT Business Plan – Attachment 21) and the following recommendation:


7

Staff recommends that the Entergy ICT Business Plan Proposal be approved in substantially the form presented, and that the officers of SPP be granted the authority to execute the documents necessary to develop this project.

Mr. Brown moved to approve the Entergy ICT Business Plan Proposal as presented. Ms. Bernard seconded the motion. The Members were unanimous in favor. The motion passed. Other Business Mr. Nick Brown reported that the Corporate Governance Committee is required to nominate a replacement for any committee vacancies reporting to the Board. The committee recommends that Larry Altenbaumer replace Bob Schoenberger on the Finance Committee. Mr. Brown moved for Board approval and Mr. Skilton seconded. Mr. Eckelberger asked for any objections. Hearing none, Mr. Larry Altenbaumer will serve as a member of the Finance Committee. Mr. Harry Skilton reported that the system enhancements required to implement the EIS market will necessitate amending SPP’s 2005 capital expenditures budget. SPP’s existing capital budget of $12.8M is insufficient to fully fund the new incremental capital costs associated with the system enhancements. Mr. Skilton moved to increase the approved 2005 capital budget to $18.3M. Mr. Brown seconded the motion. The Members were unanimous in favor. The motion passed. Agenda Item 10 – Future Meetings Mr. Nick Brown called attention to the future meeting schedule for 2006 and 2007 (Future Meetings – Attachment 21). He noted that the June meeting in 2006 would be changed to June 12-13. Also noted, there will be two additional meetings each year: one in June for educational purposes and one in December for administrative or organizational purposes. The meeting locations will remain the same each year. Adjournment With no further business, Mr. Eckelberger thanked everyone for participating and adjourned the meeting at 3:25 p.m. Stacy Duckett, Corporate Secretary

SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT

3Q 2005

SUMMARY

3Q 2005 1Q 2005 1Q 2005 4Q 2004 3Q 2004

Tariff Administration Service, Fees & Assessments

$37.8M (YTD) $24.7M $11.7M $40.3M $31.0M

Operating Expenses $33.4M (YTD) $21.1M $11.1M $28.4M $20.8M

Operating Cash Flow $7.7M (YTD) $1.8M $477K $18.7M $3.5M

Cash on Hand $42.8M (09/30/05) $39.0M $40.1M $47.6M $42.1M

TLR Events 115 111 31 105 128

Tags (daily average) 516 456 472 416 440

Transmission Service Requests

57,703 43,979 42,720 61,504 65,099

Transmission Service Study Queue

180 requests/104 studies

195/97 184/95 172/74 136/63

Generation Interconnection Queue

39 requests 33requests

34 requests

35requests

37requests

Stakeholder Meetings 53 41 52 55 55

FERC/State Commissions Dockets Pending

34 21 20 15 13

Legal Matters Pending 3 3 3 0 0

Executive Industry Activities 30 56 38 27 26

Number of Members 45 45 45 43 48

Withdrawal Notices 5 (2005)3 (2006)

7 (2005) 1 (2006)

8 (2005) 8 (2005) 15 (2004)2 (2005)

Staff 157 144 137 131 131


3Q 2005

NOTES TO FINANCIAL STATEMENTS Balance Sheet

• Cash balances increased by $3.7 million from the 2nd quarter. This increase resulted primarily from the positive cash flow from operations of $5.8 million partially offset by $2.1 million in capital expenditures in the 3rd quarter.

• Accounts receivable and accounts payable resulting from tariff activities are now reported on a net basis as a result of accounting rule interpretation. This effectively leaves only SPP’s administrative fee remaining in accounts receivable.

• Overall increase in A/R of $0.7 million is attributable mainly to normal activity within the A/R tariff account

• Other current assets decreased $2.0 million primarily due to the 3rd quarter billing of Schedule 12 revenue that had been accrued for in the 1st and 2nd quarters of 2005.

• Net fixed assets increased $1.3 million as SPP booked nearly $2.1 million in gross purchases during the 3rd quarter. Over $0.8 million of the purchases were related to the imbalance energy market initiative. Remainder of the increase is attributable to software and hardware purchases of $0.7 million and $0.6 million, respectively.

• Total current liabilities increased $1.5 million from the 2nd quarter primarily due to an increase in other current liabilities of $2.2 million partially offset by a decrease in accounts payable of $0.9 million. The increase in other current liabilities is attributable to the 3rd quarter addition to the FERC assessment liability of $1.8 million. Decrease in accounts payable is due to the 3rd quarter payment of several significant consulting invoices that were accrued for at June 30.

• Members’ equity increased by $2.2 million as a result of retention of earnings. Income Statement

• Revenues from tariff administration were favorable to budget by approximately $1.4 million due to the level of services taken under the tariff being greater than what was assumed in the budget.

• Revenues from fees and assessments were below budget by almost $1.0 million primarily due to SPP’s budget assumption of recovering the FERC assessment effective January 2005 when it actually did not commence until March 2005 ($0.6 million/ month).

• Miscellaneous income exceeded budget by nearly $1.7 million primarily due to the 2nd quarter catch up on revenue recognized for impact studies.

• Operating expenses fell $6.6 million short of budget primarily due to project timing/schedule changes, specifically with the shift in market implementation from March 2005 to May 2006. The expenses are still expected to be incurred. The most notable variance is the salary and benefits line item, which results from a greater number of new headcount being assumed in the budget than was actually added 2005 year to date. Additionally, the cash basis budget will cause some variance in comparison to the accrual based financial statements primarily as it relates to leases, maintenance, and insurance costs.


3Q 2005

• Νet other income/expense was favorable to budget by $1.0 million largely due to earnings on deposits being greater than what was assumed in the budget ($0.6 million) and budgeted bad debt expense not being recognized to date (0.3 million).

Cash Flow

• SPP recorded a net decrease in cash of $4.9 million through the 3rd quarter (year to date). This is primarily the result of capital expenditures of $7.5 million and the principal payment made on the 7.5% note of $5.0 million. These outflows were partially offset by the positive cash flow from operations of approximately $7.6 million.

Southwest Power Pool Balance Sheet

As of September 30, 2005

($000) Sep. 30, 2005 June 30, 2005 VarianceASSETS

Current AssetsCash & Equivalents 28,124 24,972 3,152 Restricted Cash Deposits 14,654 14,062 592 Accounts Receivable (net) 4,755 4,056 699 Other Current Assets 2,284 4,286 (2,002)

Total Current Assets 49,817 47,376 2,441 Total Fixed Assets 24,832 23,487 1,345 Total Other Assets 477 497 (20)

TOTAL ASSETS 75,126 71,361 3,766

LIABILITIES & EQUITYLiabilities

Current LiabilitiesAccounts Payable (net) 1,076 1,980 (903) Customer Deposits 14,158 13,926 231 Current Maturities of LT Debt 5,000 5,000 -Other Current Liabilities 6,788 4,590 2,198

Total Current Liabilities 27,022 25,496 1,526 Long Term Liabilities

7.50% Senior Notes - 2008 10,000 10,000 -4.78% Senior Notes - 2011 25,000 25,000 -

Total Long Term Liabilities 35,000 35,000 -Total Liabilities 62,022 60,496 1,526 Total Members' Equity 13,105 10,865 2,239

TOTAL LIABILITIES & EQUITY 75,126 71,361 3,766

Southwest Power PoolStatement of Income and Members' Equity

For the Nine Months Ended September 30, 2005

($000)Actual

Jan - Sep 05Budget

Jan - Sep 05Variance to Budget

Actual Jan - Sep 05

Actual Jan - Sep 04 Variance

Ordinary Income/ExpenseIncome

Tariff Administration Service 31,725 30,293 1,432 31,725 29,225 2,500 Fees & Assessments 6,072 7,032 (959) 6,072 1,807 4,265 Contract Services Revenue 37 - 37 37 - 37 Miscellaneous Income 2,464 720 1,744 2,464 1,253 1,211

Total Income 40,298 38,045 2,253 40,298 32,285 8,013

ExpenseSalary & Benefits 12,445 14,265 (1,820) 12,445 10,621 1,824 Employee Travel 484 549 (65) 484 411 73 Administrative 1,467 1,546 (79) 1,467 812 656 Assessments & Fees 5,931 5,932 (0) 5,931 503 5,429 Meetings 264 307 (44) 264 233 30 Communications 1,306 2,460 (1,154) 1,306 878 429 Leases & Maintenance 1,587 3,168 (1,581) 1,587 2,282 (695) Services 6,877 6,673 204 6,877 5,106 1,771 Regional State Committee 956 1,370 (413) 956 2 955 Depreciation & Amortization 2,059 3,661 (1,602) 2,059 3,332 (1,273)

Total Expense 33,377 39,931 (6,554) 33,377 24,179 9,198

Net Ordinary Income 6,920 (1,886) 8,807 6,920 8,105 (1,185)

Other Income/ExpenseOther Income

Asset - - - - 2 (2) Withdrawal Obligation Income - - - - 641 (641) Interest Income 645 90 555 645 137 508

Total Other Income 645 90 555 645 780 (135)

Other ExpenseInterest Expense 1,756 1,969 (213) 1,756 1,573 183 Bad Debt Expense - 250 (250) - 53 (53)

Total Other Expense 1,756 2,219 (463) 1,756 1,626 130

Net Other Income (Expense) (1,111) (2,129) 1,018 (1,111) (846) (265)

Net Income 5,810 (4,015) 9,824 5,810 7,259 (1,449)

Southwest Power Pool Statement of Cash Flows


($000) Jan - Sep 05OPERATING ACTIVITIES

Net income 5,810 Adjustments to reconcile net income (loss)to net cash provided by operations:

Depreciation 1,998 Amortization 61 Changes in assets and liabilities: Accounts receivable (561) Accrued revenue (793) Prepaid expenses (1,203) Accounts payable (581) Other current liabilities 5,204 Customer deposits (2,272)

Net cash provided by operating activities 7,664

INVESTING ACTIVITIESPurchase of property and equipment (7,536)

Net cash used by investing activities (7,536)

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

Net cash used by financing activities (5,000)

Net cash decrease for period (4,873)

Cash at beginning of period 47,651 Cash at end of period 42,778

Southwest Power Pool Capital Expenditures


($000)Jan - Sep 05 Budget Variance to Budget 2005 Budget

Imbalance Market 4,054 5,092 (1,038) 10,722 Primary Operations Center 344 2,667 (2,323) 3,650 Maintenance - Software 1,597 1,677 (80) 1,716 Maintenance - Hardware 1,541 2,195 (653) 2,213 Total Capital Expenditures 7,536 11,631 (4,094) 18,300


3Q 2005

RELIABILITY COORDINATION TLR Events per Quarter

0

20

40

60

80

100

120

140

# of

Eve

nts

SPP 115 111 31 105 128

3Q-05 2Q-05 1Q-05 4Q-04 3Q-04

3Q05 v. 3Q04 shows a slight decrease.

MW Curtailed due to TLR

0

20000

40000

60000

80000

100000

120000

140000

160000

180000

3Q-05 2Q-05 1Q-05 4Q-04 3Q-04

MW Firm

Non-Firm

3Q05 v. 3Q04 shows a slight decrease in MW curtailed due to TLR.


3Q 2005

SCHEDULING

Daily Average Tags Processed

0

100

200

300

400

500

600

Num

ber o

f Tag

s

SPP 516 456 473 416 440

3Q-05 2Q-05 1Q-05 4Q-04 3Q-04

3Q05 v. 3Q04 shows increase in the number of tags processed.

TARIFF ADMINISTRATION

Total Requests Submitted

0

10000

20000

30000

40000

50000

60000

70000

SPP 57703 43979 42720 61504 65099

3Q-05 2Q-05 1Q-05 4Q-04 3Q-04

3Q05 v. 3Q04 shows decrease in total transmission service requests.


3Q 2005

% of Total Requests that are Confirmed

0%

10%

20%

30%

40%

50%

60%

SPP 48% 36% 56% 32% 29%

3Q-05 2Q-05 1Q-05 4Q-04 3Q-04

3Q05 v. 3Q04 shows strong increase in percentage of transmission service requests confirmed.


3Q 2005

QUEUE STATUS REPORT Transmission Service Request Queue

Number of requests/studies = 180/104, representing 15,249 MW Number of non-DC Tie requests/studies = 87/71, representing 6,239 MW There are 82 requests/26 studies for DC Tie requests representing 8,456 MW that cannot be processed due to impending DC Tie competition. During the same period last year, there were 136 requests/63 studies in process, representing 18,090 MW. There were 76 requests/24 studies for DC Tie requests representing 8,072 MW that could not be processed due to impending DC Tie competition. Generation Interconnection Queue

Number of requests = 39, representing 7,260 MW • Number of wind requests = 27, representing 4,833 MW • Number of fossil fuel requests = 12, representing 2,427 MW Number of requests with Interconnection Agreement pending = 10 Interconnection Agreements signed during 2005 = 3 During the same period last year, there are 37 requests in process (26 wind; 11 fossil fuel) representing 9,078 MW (4,279MW wind; 4,799 MW fossil fuel). There were 9 Interconnection Agreements pending.


3Q 2005

SPP DOCKETS AT FERC/STATE COMMISSIONS

DOCKET

NUMBER CASE NAME DESCRIPTION CURRENT STATUS

RT04-01and ER04-48

Southwest Power Pool, Inc.

SPP filed a proposal for recognition as an RTO. By order issued February 10, the Commission accepted SPP’s proposal for recognition as an RTO subject to conditions and compliance filing requirements. On October 1, 2004 FERC issued an Order on SPP’s August 2, 2004 compliance filing. The order recognized SPP as an RTO and required several additional compliance steps by November 1. FERC then issued a February 11, 2005 Order addressing SPP’s compliance filings and directing SPP to make additional filings. SPP filed a proposal for revisions to SPP’s Bylaws and Membership Agreement to provide for independence of SPP’s compliance function, clarify a SPP Member’s Withdrawal/ Termination Obligations, and, in compliance with the Commission’s February 11 Order, provide for a Fee Waiver.

On August 9, 2005 SPP submitted a filing providing for revisions to its Bylaws and Membership Agreement. On August 26, 2005, SPP submitted its compliance filing and progress report, addressing Grandfathered Agreement conversion issues, pursuant to FERC’s October 2, 2004 order in this proceeding and in fulfillment of SPP’s August 2, 2004 commitment. On September 20, 2005 FERC issued an order which: granted in part and denied in part the rehearing requests; conditionally accepted SPP compliance filing; and directed SPP to submit a compliance filing within 30 days.

RM05-5-000

Standards For Business Practices And Communications Protocols For Public Utilities

The FERC issued a NOPR with regard to a proposal to include in its regulations by reference certain Standards for Business Practices and Communication Protocols for Public Utilities. These standards would be those promulgated by the North American Energy Standards Board’s (“NAESB”) Wholesale Electric Quadrant (“WEQ”).

On July 1, 2005, SPP joined comments filed by the ISO/RTO Council encouraging FERC to accept some standards while allowing review of others.


3Q 2005

DOCKET


ER05-666 Southwest Power Pool, Inc.

SPP filed certain Tariff modifications providing for Generation Imbalance Service (Schedule 4-A), Limitation of Liability, refinement of monthly demand charge and zone transmission load, modification of Schedule 9 to allow a Transmission Owner to avoid paying itself for Network Service, redispatch for Short-Term Firm Transmission Service, and modifications to reflect correct Zone name references and clerical errors.

On July 21, 2005, the FERC issued an order in this docket. In the Order, all provisions of the filing were accepted with two exceptions. On August 22, 2005, SPP submitted its compliance filing, providing revisions to its OATT pursuant to the Commissioner’s Order issued 7/21/05. FERC issued an Order Granting Rehearing for Further Consideration on September 21, 2005.

ER05-1285 Southwest Power Pool, Inc

On August 2, 2005, SPP filed at the FERC three sets of revisions to its OATT: (1) to modify the definition of Transmission Facilities by adding a new Attachment AI and revising the Definitions section; (2) to revise Attachment L to provide for the distribution of revenue between multiple entities owning transmission facilities in a single zone (sometimes referred to as compensation for customer-owned transmission facilities); and (3) to revise Schedule 1 (Scheduling, System Control and Dispatch Service) to eliminate assessment of multiple scheduling charges for a single reservation or transaction and to revise Attachment L (Treatment of Revenues) to provide for the allocation of scheduling revenue under the new rate design

On September 30, 2005, the FERC accepted the proposed revisions to the Schedule 1 and Attachment L. The FERC also accepted the proposed revisions to the Definitions section and the new Attachment AI, but only after SPP made modifications to the definitions and Attachment AI to comply with the order.


3Q 2005

DOCKET



On February 11, 2005, SPP submitted an Agreement for Wholesale Distribution Services Charges between Kansas Electric Power Cooperative, Inc and the Empire District Electric Co.

On May 12, 2005, SPP submitted a compliance filing consistent with a 4/13/05 unpublished letter order, providing SPP’s corrected designation to the Agreement for Wholesale Distribution Service Charges between Electric Power Cooperative, Inc and the Empire District Electric Company and a refund report. FERC accepted SPP’s submittal on August 19, 2005.

ER05-1051 and ER05-

1052

Westar Energy, Inc.

On May 31, 2005, Westar and SPP separately filed an unexecuted service agreement to provide KPP with ancillary services. Under the Agreement, KPP may self-supply all or a portion of its ancillary services as allowed in the SPP OATT. SPP filed to remove the reference to the transmission owner from Section 3.0 of the KPP Ancillary Services Agreement and there is to be a Settlement Conference regarding the unexecuted ancillary services agreement between SPP and KPP

On September 7, 2005, an order was issued scheduling a settlement conference for Friday, October 7, 2005.


In a May 2 Filing, Westar proposed to (a) update Westar's rates to recover the costs of providing transmission and ancillary service; and (b) adopt a formula rate approach to determining and keeping the transmission service rates current. SPP submitted this filing to merely track the proposed rates for transmission service applicable to the Westar pricing zone.

The effective date for Westar’s filing has been delayed for five months subject to hearing and settlement proceedings. No other FERC action has been taken on this docket.


3Q 2005

DOCKET



On February 8, 2005, SPP filed a revision to its open access transmission tariff to add Schedule 12 in order to recover SPP's payments to FERC's Annual Charges.

Interventions and Protests have been filed and SPP filed an answer to the protests on April 4, 2005. On April 8, 2005 FERC accepted the filing and suspended it, subject to the outcome of Settlement and Hearing Proceedings. After initiating settlement proceedings, FERC issued an order on clarification on June 3, 2005 and accepted the tariff revisions as filed.


SPP filed Attachment AD on November 1, 2004 to provide an interim agreement between SPP and Southwestern Power Administration until a permanent agreement can be executed.

On February 8, 2005, SPP filed a supplement to Attachment AD and a revised agreement. On March 31, 2005, FERC accepted Attachment AD and the revised agreement. The SPA coordination agreement was filed on May 16, 2005. FERC accepted the agreement by letter order on June 30, 2005.

ER04-1232 Southwest Power Pool, Inc. SPP filed an amendment to the SPP OATT to implement a rate change proposed by Excel for Southwestern Public Service in Docket ER04-1174-000.

FERC accepted the revisions, suspended them for five months, to become effective June 1, 2005, subject to refund, and established hearing and settlement judge procedures. On February 14, 2005, FERC granted rehearing to allow additional time to consider the issues.


3Q 2005

DOCKET


ER99-4392 East Texas Electric Cooperatives, Inc. v. FERC

SPP filed revisions to its tariff in order to implement network integration transmission service. FERC granted a rehearing request in accordance with a Court decision to remand the case to FERC. At OG & E’s request, FERC decided the major issue in the case was whether redispatch is required to sustain non-firm service, and FERC found that it was not.

On February 11, 2005, FERC accepted SPP’s past compliance filing and directed SPP to make a new compliance filing. SPP filed on March 14, 2005. On June 3, 2005 FERC issued an order on clarification that affirmed its position and accepted SPP’s tariff filing.


On June 15, 2005, SPP submitted proposed revisions to its Open Access Transmission Tariff to incorporate Energy Imbalance Market and Market Monitoring Plan, effective 3/1/06. On September 6, 2005, SPP filed an answer to comments and protests of SPP’s filing of tariff revisions to implement an energy imbalance market.

On September 19, 2005 FERC issued an order on proposed tariff revisions rejecting SPP’s filing and providing guidance on the following issues: (1) reliable and stable market operations; (2) market-based rates; and (3) mitigation and monitoring provisions. SPP needs to submit revised, comprehensive energy imbalance and market monitoring and mitigation plans.


3Q 2005

DOCKET


ER04-1232 Southwest Power Pool, Inc. Filing of an amendment to the SPP OATT to implement a rate change proposed by Excel for Southwestern Public Service in Docket ER04-1174-000

FERC accepted the revisions, suspended them for five months, to become effective June 1, 2005, subject to refund, and established hearing and settlement judge procedures. On February 14, 2005, FERC granted rehearing to allow additional time to consider the issues.


On February 28, 2005, SPP submitted a filing to revise its Tariff to implement a regional transmission cost allocation proposal with regard to new transmission upgrades. This proposal was developed by the Regional State Committee.

FERC accepted SPP’s filing of the proposal to become effective on May 5, 2005. SPP then made a compliance filing on May 23, 2005 providing for revisions to its Tariff. FERC then granted rehearing on June 22, 2005. No final decision has been made in this docket.

ER99-4392 East Texas Electric Cooperatives, Inc. v. FERC

SPP filed revisions to its tariff in order to implement network integration transmission service. FERC granted a rehearing request in accordance with a Court decision to remand the case to FERC. At OG & E’s request, FERC decided the major issue in the case was whether redispatch is required to sustain non-firm service, and FERC found that it was not.

On February 11, 2005, FERC accepted SPP’s past compliance filing and directed SPP to make a new compliance filing. SPP filed on March 14, 2005. On June 3, 2005 FERC issued an order on clarification that affirmed its position and accepted SPP’s tariff filing.


SPP made revisions to its Tariff in order to incorporate Aquila Networks-L&P ("L&P'), Aquila Networks-MPS ("MPS"), and Aquila Networks-WPK ("WPK") as Transmission Owners participating in the SPP Tariff.

FERC accepted the filing on June 30, 2005.


3Q 2005

DOCKET



SPP filed an unexecuted Network Integration Transmission Service Agreement between SPP-OG&E-OMPA to rollover grandfathered transmission from the OG&E tariff to the SPP Tariff

On August 23, 2005 a FERC settlement judge issued a report recommending continuance of the current settlement procedures.

ER05-1012; ER05-1072

Union Electric Co. d/b/a Ameren UE

American Electric Power Co.

Ameren UE & AEP-PSO each submitted a notice of cancellation of an amended interchange agreement known as the Mo-Kan-Ok agreement.

On September 2, 2005 Associated Electric Cooperative, Inc submitted its answer to Xcel Energy Services, Inc.’s August 22, 2005 request for clarification of the Commission’s July 22, 2005 order in this proceeding. AEC contends that the Commission should reject the Request for Clarification and affirm the July 22, 2005 Order under which the Commission accepted the notices of cancellation of the Mo-Kan-Ok Agreement.. No FERC action has been taken in this docket.

ER04-699-000; ER05-

1065 Entergy Services, Inc.

Federal Energy Regulatory Commission proceedings concerning Entergy’s ICT proposal.

Entergy filed its enhanced ICT proposal on January 3, 2005. On March 11, 2005 FERC conditionally accepted Entergy’s filing. SPP intervened on June 7, 2005 and has filed testimony in this docket. No FERC decision has been made.


3Q 2005

DOCKET


ER05-925; ER05-990

Westar Energy, Inc.

FERC issued an Order accepting SPP’s May 19, 2005 filing for revision of the rates for the Westar Zone and suspending it for five months, to become effective December 1, 2005, subject to refund and subject to the outcome of Dockets. December 1, 2005 is the effective date for Westar’s rate increase, subject to refund and subject to the outcome of Docket No. ER05-925-000.

On August 19, 2005 FERC issued an order of the Chief Judge adopting a protective order, pursuant to Westar’s August 15, 2005 motion for adoption of a protective order. On August 29, 2005, FERC issued an order of the Chief Judge continuing settlement judge procedures.

ER05-1151-000; ER05-

226-001

Southwest Power Pool, Inc. On June 27, 2005, SPP filed of a revision to the PSO-GRDA interconnection agreement, effective dates of December 1, 2004 and May 26, 2005.

On August 5, 2005 FERC accepted for filing, effective 12/01/04 and 5/26/05, SPP’s Revised Interchange and Interconnection Agreement designated as Service Agreement 1135.


SPP filed to provide a 10 month report on the results of Attachment AA in compliance with the Commission’s October 5, 2004 Order in ER04-833 and requested an extension of the program another year

FERC issued a Notice of Filings # 1 acknowledging the 8/05/05 filing of SPP’s status but has not issued a decision in this docket..

ER04-434-004 Southwest Power Pool, Inc. SPP filed revised tariff sheets in compliance with Order 2003-C.

On August 15, 2005 ,SPP filed revised tariff sheets to SPP's OATT incorporating the changes to the pro forma LGIP and LGIA identified in Appendix A to Order No. 2003-C. On September 30, 2005 FERC issued a Letter Order accepting SPP’s filing, to become effective July 18, 2005, as requested.


3Q 2005

DOCKET


ER05-989-001 Kansas City Power & Light Co and the City of Garnett, Kansas

SPP filing of Amendatory Agreement No. 4 to the Municipal Participation Agreement between KCPL and Garnett, KS

On September 12, 2005, in compliance with FERC’s July 13, 2005 order, SPP filed Amendatory Agreement No. 4 to the Municipal Participation Agreement between Kansas City Power & Light Company and the City of Gamett, Kansas.

ER05-651-003 Southwest Power Pool, Inc. SPP filing in compliance with FERC’s August 25, 2005 Order on the SPP, PSO, FPL Cowboy interconnection agreement.

On September 27, 2005, SPP submitted a revised version of the Large Generator Interconnection Agreement between SPP, FPL Energy Cowboy Wind, LLC, and Public Service Company of Oklahoma. On October 3, 2005 FERC acknowledged this filing via its Combined Notice of Filings # 1.

ER03-765-001 Calpine Oneta Power, L.P.

Calpine initiated this proceeding by filing its proposed rate schedule on April 22, 2003, seeking to collect from SPP its alleged reactive power revenue requirement of $2,455,169.96 totaling over $5.5 million dollars to date and growing, relating to the alleged provision of reactive power services from the Calpine Oneta facility.

On September 16, 2005, SPP filed its Reply Brief in response to the Initial Brief of Calpine pursuant to Rule 706 of FERC’s Rules of Practice and Procedure and the December 22, 2004 Order Setting Procedural Schedule. An initial decision is scheduled by November 3, 2005.

ER05-1300 Southwest Power Pool, Inc On August 5, 2005, SPP filed a status report on the implementation of Attachment AA of the SPP OATT.

On September 20, 2005, the FERC accepted SPP’s filing and extended Attachment AA for one year.


3Q 2005

DOCKET


RM04-12

Financial Reporting and Cost Recovery Practices for Regional Transmission Organizations and Independent System Operators

Comments due NOPR on Accounting and Financial Reporting for Public Utilities Including RTOs

Many entities filed comments in response to FERC’s June 2, 2005 notice of proposed rulemaking.


3Q 2005

DOCKET


ER05-652 Southwest Power Pool, Inc. FERC's Order on Rehearing and Compliance Filing on SPP's Cost Allocation Proposal

On September 20, 2005 FERC issued an Order on Rehearing and Compliance Filing addressing rehearing requests of its April 22, 2005 order on SPP's proposal for a regional transmission cost allocation plan and accepting SPP's May 5, 2005 compliance filing, subject to further compliance filings. FERC denied rehearing of most issues, but granted rehearing of a limited number of issues. FERC ordered SPP to remove the fuel diversity provision from the non-exhaustive list of waiver criteria, upheld the decision that Attachment Z does not contain provisions for impermissible "and" pricing, and granted certain clarifications with respect to Attachment Z. A compliance filing is required by October 20, 2005. SPP is permitted to file a tariff provision clarifying that the right of first refusal provision is a cost allocation mechanism, not an ownership mechanism.


3Q 2005

DOCKET


Arkansas 04-137-U

Southwest Power Pool, Inc. SPP’s CCN Filing with APSC for recognition as a public utility.

On October 13, 2004, SPP made a CCN Filing with APSC for recognition as a public utility and asked for disclaimer of regulation. SPP filed testimony and the Cost/Benefit Study on June 17, 2005. The APSC has submitted numerous data requests and SPP complying with the requests. On September 29, 2005, the APSC issued an order granting Staff's motion to consolidate the applications of the SPP Transmission Owners with SPP's docket.

Louisiana U-28155

Entergy Services, Inc. Louisiana Public Service Commission proceedings concerning Entergy’s ICT proposal

SPP filed an intervention on September 13, 2004. Entergy filed its enhanced ICT proposal on January 6, 2005. SPP has filed both direct testimony and cross-answering testimony regarding SPP’s capability to perform the ICT function. A hearing is set for October 17, 2005.

Arkansas 04-050-U

Entergy Services, Inc.

An Investigation regarding Entergy Arkansas, Inc.’s participation in an Entergy-only independent transmission system administrator structure as compared to its participation in the Southwest Power Pool Regional Transmission Organization.

SPP has filed initial and reply comments in the proceeding.


3Q 2005

DOCKET


Missouri EO-2006-0141

and EO-2006-0142

In the Matter of the Applications of the Empire District Electric Company and Kansas City Power & Light Company for Authority to Transfer Functional Control of Certain Transmission Assets to SPP

Applications with the Missouri Public Service Commission requesting approval to transfer the functional control of certain transmission assets to the SPP, to continue participation in the SPP RTO, and to take network integration transmission service from SPP to serve each company’s retail load in Missouri.

On September 28, 2005 the Empire District Electric Company and the Kansas City Power & Light Company each filed an application with the Missouri Public Service Commission requesting approval to transfer the functional control of certain transmission assets to the SPP, to continue participation in the SPP RTO, and to take network integration transmission service from SPP to serve each company’s retail load in Missouri. On September 30, 2005 SPP filed an Application to Intervene in the above-referenced matters, submitting in support of its application the SPP RSC Cost-Benefit Analysis and the testimony of Les Dillahunty; Ralph L. Luciani and Ellen Wolfe; and Richard A. Wodyka.

Kansas 06-SPPE-202-

COC Southwest Power Pool, Inc.

An application of SPP for a Certificate of Convenience and Authority for the limited purpose of managing and coordinating the use of certain transmission facilities located within Kansas.

On August 31, 2005 SPP applied for a Certificate of Convenience and Authority for the limited purpose of managing and coordinating the use of certain transmission facilities within Kansas. No decision has been issued in this docket.


3Q 2005

LEGAL MATTERS PENDING

Party/Description Issue

Reliant Energy Disputed withdrawal fee.

City of Jonesboro Demand letter sent for repayment of membership overpayment.

EEOC Charge Former SPP employee filed EEOC charge. Charge was dismissed.

Mirant Corporation Bankruptcy SPP CFO deposed.


3Q 2005

EXECUTIVE INDUSTRY ACTIVITIES

Executive Event

Nick Brown Oklahoma Bill Signing (July 6) Utilities State Government Organization, Palms, SC (July 11) Kansas Electric Coop Annual Meeting (August 1) Electric Power Research Institute Board Meeting, California (Aug. 6-10) Electric Power Supply Association Executive Conference, Washington,

DC (Aug. 30)

Les Dillahunty National Society of Professional Engineers, Chicago (July 7-9) Member Meeting: American Electric Power (July 20) Entergy ICT Deposition for Louisiana Public Service Commision, New

Orleans (Aug. 24) Missouri Public Service Commission Informational Proceeding

(KCPL/EDE/SPP), Jefferson City (Aug. 30) Member Meeting: Golden Spread (Sep.1) Member Meeting: Golden Spread, Empire, Sunflower (Sep. 2) Oklahoma Emerging Energy Technology Conference, Norman (Sep. 27)

Tom Dunn Missouri Municipal Utility Meeting (Marshall, Slater, Salisbury, Carrolton, Higginsville, KCPL, MJMEUC) (Sep. 1)

Member Meeting: Westar, Wichita (Sep. 26)

Stacy Duckett West Africa Power Pool, SPP Office (Aug. 8) ISO/RTO Council General Council Group, California (Sep. 26-27)

Carl Monroe SPP-MISO Seams Agreement Coordinating Committee (July 19) West Africa Power Pool, SPP Office (Aug. 8) Member Meeting: Golden Spread (Sep. 1) Conference Call with FERC on Long-Term Transmission Rights (Sep. 2) NERC Operating Committee, Dallas (Sep. 14-15) Member Meeting: Westar Visit (Sep. 26)

Charles Yeung ISO/RTO Council, Alberta (July 11) NERC FMWG, Chicago (July 13) RMC, San Diego (Aug. 1) NERC BOT, San Diego (Aug. 1) NERC FMWG (Aug. 30) ISO/RTO Council RLC (Sep. 9) RMC, Dallas (Sep. 14) NERC Regional Delegation Task Group Conference Call (Sep. 27)


3Q 2005

WITHDRAWAL LETTERS MEMBERS EFFECTIVE DATES Cleco Corporation 10/31/06 Grand River Dam Authority 10/31/05 Louisiana Energy & Power Authority 10/31/06 City of Lafayette Utilities System 10/31/06 Midwest Energy 10/31/05 Oklahoma Municipal Power 10/31/05 The Empire District Electric Company 10/31/05 Westar Energy 10/31/05


3Q 2005

STAFFING REPORT

SPP Employee count as of January 1, 2005:

131

1Q New hires: 2Q New hires: 3Q New hires:

8 11 16

YTD Terminations:

1 – Retiree 6 – Voluntary termination 1 – Involuntary termination 1 – Interns (part time/seasonal)

9

SPP Employee count as of September 30, 2005:

157

SPP Employee count as of June 30, 2005:

144

There are 206 full time employees and 2 part time employees in the 2005 budget. (These numbers include positions added mid-year.)

Southwest Power Pool, Inc. COMPLIANCE COMMITTEE

Report to the Board of Directors/Members Committee October 25, 2005

APPEAL PROCESS

Organizational Roster The following members represent the Compliance Committee:

Josh Martin, Chair Phyllis Bernard Quentin Jackson Stacy Duckett

Director Director Director SPP Staff Secretary

Background The Compliance Committee is charged with hearing appeals from members related to findings by the Compliance Department of SPP. Until recently, no such appeal to the Compliance Committee had ever occurred, and therefore no process had been developed. Analysis The Compliance Committee developed and used the attached process for hearing an appeal recently brought to it. The process worked well for all involved. As such, the Committee has adopted this process going forward. It also suggests that this would be a suitable process for all appeals heard by an organizational group of SPP. Recommendation The Compliance Committee recommends approval of this process for appeals heard by the Committee. The Committee also recommends that the Board direct the Markets and Operations Policy Committee and its working groups to implement an appeals process, which may be the same. Action Requested Approval

Approval: Corporate Governance Committee September 28, 2005

Approved by the Compliance Committee September 28, 2005

PROCESS FOR APPEAL OF COMPLIANCE ISSUES TO THE COMPLIANCE COMMITTEE 1

October 2005 SPP Member organizations may appeal a finding of non-compliance by the SPP Compliance Department. As outlined in the Compliance Program, an appeal should first be made to the SPP Organizational Group responsible for the Criteria at issue. Any further appeal(s) may be made to the Markets and Operations Policy Committee (MOPC) and/or to the Compliance Committee (CC). When making an appeal to the Compliance Committee, the following procedure will be applicable.

1) The Appellant must notify, in writing, the Director of Compliance and/or the Staff Secretary to the CC of its request for a review by the CC.

2) The Staff Secretary will notify the CC of the request and develop a timeline for hearing the appeal.

3) The Appellant and the Director of Compliance will submit written statements of their respective positions, as well as any supporting documentation. This must include the findings of previous review(s) by other Organizational Groups.

4) The Staff Secretary will seek other information/documentation as requested by the representatives from the CC.

5) A session will be scheduled (live or teleconference) at which the parties will present their respective positions; the representatives from the CC will seek additional information/clarification from the participants as needed.

6) The CC will reconvene to deliberate within three (3) business days of the session. 7) The CC will issue a Determination to the participants, in writing, within thirty (30) days of the

session. This Determination will be presented at the next regular Board of Directors/Members Committee meeting.

Participants in the appeal session will include:

• The members of the Compliance Committee • The Staff Secretary • A representative for the Appellant(s) • SPP Director of Compliance • A representative from each SPP Organizational Group that has heard an appeal on the issue

Other interested parties may be allowed to participate solely at the discretion of the Chairman of the CC. If the appeal is generally a policy interpretation that impacts multiple parties, the Chairman may conduct it in an open session available to all interested parties. If the appeal involves proprietary and/or competitive information, it will be conducted in a closed session. Participants will be notified in advance whether the session will be open or closed.

1 Once approved, this process will be integrated into the Compliance Program documentation related to appeals.

Southwest Power Pool, Inc.

COMPLIANCE COMMITTEE

September 20, 2005

Determination of Appeal

Participating Parties

Josh Martin, Chair Phyllis Bernard Quentin Jackson Bob Cochran Mike Gammon Heidt Melson Ron Ciesiel

Director Director Director Representing Appellants Operating Reliability Working Group System Protection and Control Working Group SPP Director of Compliance

Background

On August 15, the SPP Compliance Committee heard an appeal of a finding of non-compliance. The appealing parties (six members) were represented by Mr. Bob Cochran from Southwestern Public Service (SPS); the SPP Compliance Department was represented by Mr. Ron Ciesiel, Director of Compliance.

The appeal regarded the results of an Under Frequency Load Shedding Survey conducted to test compliance with SPP Criteria 7.3. The appealing parties were found to be out of compliance, necessitating notification to NERC. NERC policy requires the public posting on its website of the names of entities violating criteria.

The appeal to the Compliance Committee follows appeals to the System Protection and Control Working Group (SPCWG) and the Operating Reliability Working Group (ORWG). These SPP organizational groups are responsible for SPP Criteria. The positions of the appealing parties and the Compliance Department are detailed in written statements provided in advance of the teleconference (attached).

Mr. Joshua Martin, Chairman of the Compliance Committee requested each side provide oral statements summarizing their written statements. Committee members (Martin, Ms. Phyllis Bernard and Mr. Quentin Jackson) sought additional information from the representatives. They also directed questions to Mr. Mike Gammon (representing the ORWG) and Mr. Heidt Melson (representing the SPCWG). The Committee later reconvened to deliberate.

Analysis

The parties themselves do not dispute that they were in violation of the criteria. Results from past audits indicate that these were not isolated, intermittent incidents of non-compliance; but rather, that for the four annual compliance surveys performed by SPP from 2001 to 2004, three of the

companies have been out of compliance for all periods; two of the companies have been out of compliance for three of the periods; and one company has been out of compliance for two of the periods. The request of the parties was for leniency in the imposition of sanctions due to (a) on-going efforts to refine criteria on this issue, and (b) concern about unidentified consequences stemming from NERC's public posting of the non-compliance.

Determination

The issue for the Compliance Committee was whether SPP’s Compliance Department erred in finding the members out of compliance with SPP Criteria. Upon consideration of the facts presented, the Compliance Committee determines that the Compliance Department did not err in finding the members out of compliance with SPP Criteria 7.3. The Criteria require that an entity meet the load shedding requirements at each stage, not just in total. The members cited clearly did not do this.

The committee members are sensitive to the fact that a finding of non-compliance results in a report to NERC and public posting of the violation. However, the ability to reliably operate the transmission grid is paramount; the risks associated with unreliable operation are too great to overlook. The next step in the process has been laid out by NERC: SPP must report the incidents of non-compliance to NERC to be posted on the NERC web site. NERC's actions at this point are not within SPP's authority to control, nor is SPP afforded flexibility in its obligation.

Additional Remarks

The criteria are developed through a detailed, intensive collaborative process between technical experts among the membership in consultation with and reference to national standards for reliability. The ORWG and SPCWG are currently considering revisions to the Criteria relevant to this appeal. While the ultimate outcome of that process is not known, the Compliance Committee encourages these organizational groups to continue their work and bring it to conclusion expeditiously and will recommend that the Board of Directors monitor the progress closely.

Transmission Operations 7/21/05 6086 West 48th Street Amarillo, Texas 79109

SPP Compliance Committee C/O Ron Ciesiel, Compliance Director Southwest Power Pool 415 N. McKinley, 800 Plaza West Little Rock, AR 72205-3020 Gentlemen, Southwestern Public Service Company dba Xcel Energy (SPS) believes that the pending finding that SPS is in violation of the Southwest Power Pool (SPP) Compliance Program Planning Measurement IIIDM2; Under Frequency Load Shedding Program (UFLS) for 2004 should be reversed. We believe that we met the intent of the SPP Criteria, that we have been caught by an unintended consequence of the Criteria’s construction and don’t deserve the public embarrassment that a confirmed violation will produce. We contend that it was not the intent of the Criteria’s framers to penalize a member for compliance survey results such as SPS and other members had. It sometimes happens that rules and criteria are written without the full implications of the rule being realized by the writers. When the full impacts of the written rule become apparent, the writers then undertake to fix the rule. Included with this appeal document is a letter from Southwestern Power Administration (SPA) dated November 19, 2004. In that letter SPA makes good arguments as to the Criteria’s intent versus its application to compliance. It was SPA’s initial appeal of their compliance violation finding and their arguments that sparked the current effort to revise the SPP UFLS Criteria. We offer the ongoing effort by SPP’s committees to revise the SPP Criteria for UFLS as evidence of the Criteria’s intent and SPP’s membership’s desire to fix the Criteria. While the final form of that revision has yet to be set, both the Operating Reliability Working Group (ORWG) and the System Protection and Control Working Group (SPCWG) have approved the essential concept. That essential concept recognizes the difficulty of building a control system that can shed 10% of a member’s load at any and every possible time. Engineering design is a constrained compromise between conflicting factors. The Criteria change effort underway recognizes the engineering compromises between achieving a load shed to arrest a frequency decline, the cost to build the control scheme, and the end power users’ load behavior which varies by time of day and by season.

Page 1

Transmission Operations 7/21/05 6086 West 48th Street Amarillo, Texas 79109

Both the ORWG and SPCWG have agreed in principle to a Criteria that allows a member to shed less than 10% of their load at the second or third under frequency step as long as the cumulative load shed is at least 20% at the second step and at least 30% at the third step. SPS and other members with pending compliance violations of this Criterion would have been found compliant if this change had been made prior to the August 26, 2004 UFLS compliance survey. Their surveys’ results are provided with these members’ consent and is shown in the table below: SPP Member Name

First step percent load shed

Second step percent load shed

Third step percent load shed

Total percentage of load shed

Southwestern Public Service Company

12.99% 8.68% 9.60% 31.27%

City of Independence

11.39% 11.24% 8.0% 30.63%

Southwestern Power Administration

14.95% 8.40% 9.02% 32.38%

City of Lafayette

13.65% 9.97% 7.94% 31.55%

We respectfully request in light of this information and the ongoing effort to change the SPP UFLS Criteria that the pending compliance violation for SPS and the other similarly situated members be set aside. If you are unwilling to take that step until the proposed Criteria change is final and approved, we respectfully request that you direct the compliance violation continue to be held as pending until the Criteria change has been either approved or disapproved. Then at that time we respectfully request that you direct that the revised Criteria be used to measure our compliance for 2004. We believe that the final state of the proposed Criteria change will be determined no later than late 2005. Thank you for your time in reviewing our appeal and considering our request. Sincerely, Bob Cochran Manager, Transmission Control Center

Page 2

Response to member appeal of 2004 UFLS findings

Documentation defending the findings of non-compliance for the six [6] SPP members involved in this appeal

Historical background The SPP Criteria requiring an under frequency load shedding [UFLS] program has been in existence for more than two decades. The foundation for the requirement came from the 1965 New York blackout. All ten [10] NERC Regions developed a similar program with minor local variations but all have the basics of load shedding at a system frequency of ~59.3hz and completing the load shedding at a frequency of ~58.7hz. SPP’s program has consisted of three steps of load shedding at 59.3hz, 59.0hz and 58.7hz with each step shedding 10% for a total load shedding of 30%. SPP Criteria 7.3 [see attached] was evaluated and updated in 2001 when the NERC/SPP Compliance Program introduced compliance monitoring of SPP’s members. The updating of § 7.3.1.3 (a) was critical to providing a clear and concise direction for the members to follow in order to maintain compliance to this standard. The questions answered by the update were:

What is the load that is used for the 10% step and total 30% calculations? Answer: The calculation is based on the current load at the time of the incident.

When must my UFLS program meet the criteria? Answer: At all times regardless of starting load point.

How can I meet the criteria? Answer: Install dynamically controlled relays that arm and disarm while following load or installing enough relays to meet the overall 30% goal but in increments shown in the chart inserted in § 7.3.1.3 (a). The term ‘Minimum Load Relief (%)’ was added to the chart.

Section 7.3.1.3 is the basis for member compliance to the NERC/SPP Compliance Program. The two SPP Working Groups responsible for the Criteria are the System Protection and Control Working Group (SPCWG) and the Operating Reliability Working Group (ORWG). Monitoring Techniques In 2000, the SPP Security Working Group [now the ORWG] conducted a summer time review of member’s UFLS program status. This survey was not used for measuring compliance to the SPP Criteria but as an informational survey for use by the SWG. This technique was being used in the ERCOT region and the SPP SWG agreed to perform the survey to determine its usefulness at SPP. The survey consisted of SPP choosing a specific hour on a specific day and having the individual members report their total load for that hour plus the amount of load that would have been shed at each of the three (3) designated frequencies. Calculations were made for each step of the program and reported to the members.

After the 2000 survey, the SWG directed the SPP Compliance Group to perform an annual UFLS survey, near peak load conditions, to monitor the SPP members’ compliance to the SPP Criteria. These compliance surveys have been performed each

R.W. Ciesiel 9/19/2005 1


peak season since 2001 and used to monitor compliance to the SPP Criteria. In 2002, the Compliance Group added a spring UFLS survey for several reasons. The spring survey information can be used by SPP to monitor off-peak conditions and member responses to Criteria as well as provide initial data input in the 5-year Region-wide UFLS performance study required by NERC Standards [the next scheduled study is in 2006]. The spring survey was also instituted in order to give members an opportunity to review their programs and fill in gaps or complete maintenance programs before the ‘compliance survey’ performed in mid-summer. The original NERC UFLS compliance template did not have an objective set of measures to determine compliance levels. Based on discussions with the SWG, the following compliance guidelines were established and published:

SPP APPROVED COMPLIANCE LEVELS (APPROVED BY SWG IN 2000)

100% COMPLIANCE - Met total requirements of 30% or greater load shedding and all

steps were greater than or equal to 10%. LEVEL 1 - Met total requirements of 30% or greater load shedding but one or more steps

were less than 10% LEVEL 2 - Total load shed was less than 30% but greater than or equal to 20% LEVEL 3 - Total load shed was less than 20% but greater than or equal to 10% LEVEL 4 - Total load shed was less than 10% These guidelines were used to assess compliance to the SPP Criteria for the 2001 through 2003 summer surveys. In 2004, the NERC Compliance Templates were re-written and approved for implementation on June 1, 2004. The UFLS template was revised to include more objective measures of a member’s compliance. The ORWG adopted the NERC levels of compliance for the 2004 UFLS survey and beyond. These levels of compliance are shown below:

Levels of Non-Compliance

Level 1 - Evaluations of entity UFLS programs for consistency with the Regional UFLS program were incomplete/inconsistent in one or more requirements of Measure III.D.M1 but is consistent with the required load shed.

Level 2 - The amount of load shedding is less than 95% of the regional requirements in any of the load steps.

Level 3 - The amount of load shedding is less than 90% of the regional requirements in any of the load steps.

R.W. Ciesiel 9/19/2005 2


Level 4 - The amount of load shedding is less than 85% of the regional requirements on any of the load steps, or evaluations of entity UFLS programs for consistency with the Regional UFLS program were not provided.

The major difference between the new NERC measures and the SPP measures is that for Levels 2 to 4 the NERC measures are pointed toward performance on individual steps versus the SPP measures the utilized total load shed as the measure. This makes the NERC standard more stringent than the SPP standard.

2004 Survey and Results The 2004 summer survey was conducted on August 26, 2004. The results were accumulated and subsequently presented to the ORWG for review. The results of the 2004 survey are attached. The recommendations for non-compliance included 6 members that managed to shed 30% or more of their initial load but did not meet the more stringent requirement of shedding a minimum of 10% at each step. These members were found to be at a Level 1 non-compliance because they met the overall goal of the 30% total but were inconsistent with the requirement to shed load at minimum of 10% steps. Letters of non-compliance were sent to members that were not in 100% compliance with the Criteria. In November 2004, Southwestern Power Administration [SPA] sent a letter to SPP asking for an appeal of the Level 1 finding. The SPP Compliance Group added the following members to the appeal because they each were in the same category as SPA: AEP West City of Clarksdale, MS City of Independence, MO City of Lafayette, LA Southwestern Public Service The SPP SPCWG and the SPP ORWG met separately in late 2004 and early 2005 to hear this appeal. These two working groups heard the appeal, reviewed the existing Criteria and published the following statement:

“The ORWG reviewed SPA's non-compliance appeal at its December 15-16 [2004] meeting. The ORWG is of the opinion that the appeal is without merit based on SPP Criteria 7 which clearly indicates that a minimum of 10% of load relief per step is required. This requirement is specified in the table included in Section 7.3.1.3.a and is referenced several times in Section 7.3.1.3.a. The ORWG noted that at least 4 previous UFLS surveys had been conducted based on this interpretation of Criteria and that even though survey results have been consistently similar to the August 2004 survey results, no questions had been raised regarding this issue.” [The SPCWG unanimously adopted this statement in early 2005 as its response to the appeal].

R.W. Ciesiel 9/19/2005 3


Upon notification that their original appeal had been denied, Southwestern Public Service [one of the original 6 members] asked for an additional level of appeal to the SPP Compliance Committee. The Compliance Committee granted the request for an appeal. SPP Compliance Group Analysis The SPP Compliance Group agrees with the analysis of the SPCWG and the ORWG that the wording of the Criteria is clear that compliance is met by shedding a minimum of 10% per step for a total of 30% or more. The appellants’ argument that the overriding intent of the Criteria is to achieve 30% load shedding without regard to the shedding at each step is negated by the words of the Criteria that state “[t]he relays shall be set to shed thirty (30%) percent total in increments of current load per step, as indicated in the chart below.” The chart then shows “Minimum Load Relief (%) ” as 10 for each step. Specific statements that qualify the meaning of general statements always trump the general statements of any criteria. The appellants also ignore the history of monitoring and measuring compliance for this standard. SPP guidelines for measuring compliance approved in 2000, and discussed above, included a requirement that 100% compliance was that each member “[m]et total requirements of 30% or greater load shedding and all steps were greater than or equal to 10%. All measurements of compliance from 2001 to 2003 used this requirement. The appellants also argue that the SPCWG and the ORWG have recognized that the Criteria should be modified to provide some flexibility in meeting the requirements of the Criteria. They state that the original appeal letter from SPA triggered a review of the Criteria and that changes that provide the requested flexibility are imminent. They also request that because a change was recognized and is imminent that they should be held to the revised standard rather than to the existing standard. The two SPP Working Groups are discussing language modifications that will provide some flexibility in meeting the requirements of the Criteria but have agreed on such language and there is no guarantee that any changes will be made in the future. Even if there are changes made to the Criteria, applying them retroactively is not in the best interest of the compliance program. If retroactive standards are applied in this case, setting a precedent, then all findings of compliance are subject to change when the rules change in the future. In order to move forward with the program from year-to-year, there must be finality to the findings, based on the standards in place at the time of the findings. In addition, the two groups that are now reviewing proposed language changes issued a very strong statement reflecting their views of the current Criteria and the rules of compliance [see above on page 4]. For these reasons, the SPP Compliance Group recommends that the non-compliance findings for the six members be upheld and confirmed. Respectfully submitted on July 29, 2005 by: Ronald W. Ciesiel SPP Compliance Director 501-614-3265

R.W. Ciesiel 9/19/2005 4

Southwest Power Pool, Inc. FINANCE COMMITTEE

Report to the Board of Directors October 25, 2005

Organizational Roster The following members represent the Credit Task Force:

Nithya Venkatesan NRG Tricia Harrod Aquila Jason Hill Aquila Brian Lawson GDS Associates, representing ETEC Lanny Keele Capline Morgan Davies Calpine Mark Soulliere Tenaska Stephanie Staska Cargill Ross Baker Aces Power Terry Smith The Energy Authority representing City Utilities of Springfield

Background The Credit Task Force was formed in November 2003 and charged with reviewing and developing credit policies and procedures to support transactions occurring under the SPP regional tariff. The Credit Task Force presented to the Finance Committee a revised Credit Policy at the Finance Committee’s March 29, 2005 meeting. The Finance Committee approved the Credit Policy as drafted, directed SPP staff to present the Credit Policy to the MOPC and request review by the RTWG to prepare the policy for submission with the SPP regional tariff, and ordered implementation of the Credit Policy as soon as practicable following acceptance by the SPP Board of Directors. The SPP Board of Directors, at their April 26, 2005 meeting, approved a recommendation from the Finance Committee to adopt the Credit Policy and implement the policy as soon as practicable but no later than the filing of the energy imbalance market rules. The Finance Committee, at the July 26, 2005 meeting of the SPP Board of Directors, resolved to file the Credit Policy with the October tariff filing.

Analysis The Credit Task Force met 4 times in September 2005 to finalize aspects of the Credit Policy implementation and address ancillary credit issues related to implementation of the Energy Imbalance Services market (“EIS”). A topic of discussion centered upon the appropriateness of implementing the Credit Policy in advance of a filing with the Commission and the consequences of doing so. A similar action in PJM resulted in PJM being required to revert back to its prior policy until the Commission was able to rule on the new policy1. SPP’s regulatory counsel participated in the meeting and was familiar with the PJM ruling. A suggestion was made to implement the policy coincident with filing the policy with the Commission. SPP believes the policy will have numerous interventions and general practice has been to implement coincident with a filing when it is believed there will be minimal interventions. A recommendation was made to recommend to the Finance Committee the Credit Policy be filed with the Commission and implementation delayed until definitive action by the Commission on the filing. This recommendation was approved with one nay vote.

1 See FERC docket ELO3-207-000

The Credit Task Force also discussed in detail the potential exposure calculation detailed within the Credit Policy. The Credit Task Force had approved the exposure calculations in meetings held in late 2004. The approved exposure calculation for EIS activity is based on the highest day’s charges incurred over the preceding year while the exposure calculation for transmission service is based on the highest monthly A/R balance over the past year. The issue raised concerned the “punitive” nature of the calculations and whether they are appropriate measures of potential exposure.

A sub-group of the Credit Task Force collaborated and developed a new methodology for calculation of potential exposure to services sold through the regional tariff. This language was approved by the Credit Task Force at its October 7, 2005 meeting with 0 nay votes

Recommendation The Finance Committee recommends the Credit Policy previously approved by the SPP Board of Directors at its April 25, 2005 meeting be amended to include the attached language concerning calculation of potential exposure. The Finance Committee further recommends the Credit Policy be filed separate from the EIS filings to allow for a request for expedited review. Additionally, the Finance Committee recommends implementation of the Credit Policy be delayed until FERC completes its review and action on the Credit Policy filing.

Approved: Credit Task Force

Finance Committee – unanimous vote

October 7, 2005

October 11, 2005

Action Requested: Approve recommendation

ARTICLE FIVE Calculation of Total Potential Exposure

5.1 Overview. The Total Potential Exposure is a calculated value applied to assure

that the Market Participant engages in activities within its Total Credit Limit. The Total Potential Exposure is based on the Market Participant’s estimated cumulative financial obligation under the Tariff or otherwise to SPP. Potential Exposure to non-payment is calculated separately for each category of Market Services and Transmission Services and then summed together to obtain the amount of Total Potential Exposure. This Article addresses the calculation and use of the value for Total Potential Exposure.

5.2 Calculation of Total Potential Exposure for A Market Participant. A Market

Participant’s Total Potential Exposure shall be the sum of the potential exposure to non-payment for Energy Imbalance Market transactions and Transmission Service transactions billed pursuant to the Tariff.

5.2.1 Energy Imbalance Market Exposure (“EIME”). Potential exposure to

non-payment associated with the Energy Imbalance Market transactions that involve physical delivery of Energy is calculated under the following formula:

EIME = IMSC + CMSC + MEME

IMSC = Invoiced Market Settlement Charges (all imbalance charges that

have been invoiced but not yet paid).

CMSC = Calculated Market Settlement Charges (all daily settlement activity that has been calculated but not yet invoiced).

MEME = Maximum Estimated Market Exposure shall be the greater of:

(a) The rolling average of the last three hundred sixty five (365) days of daily settlement activity (or a lesser period of time if 365 days of settlement activity are unavailable) times the remainder of the Potential Exposure Window, or

(b) The rolling average of the last seven (7) days of daily

settlement activity (or a lesser period of time if 7 days of settlement activity are unavailable) times the remainder of the Potential Exposure Window.

Following are examples of the calculation of Energy Imbalance Market Exposure.

Deleted: (the charges incurred on the Peak Market Activity Day in the last 365 days or a lesser period of time service has been taken, multiplied by the number of days in the Potential Exposure Window).

Example of Energy Imbalance Market Exposure Calculation:

ASSUMPTIONS: CURRENT DAY IS TUESDAY, NOVEMBER 23, 2004 CUSTOMER HAS PAID PREVIOUS WEEKLY INVOICE IN FULL(NOVEMBER 12) HIGHEST POSITIVE DAILY SETTLEMENT FOR LAST 365 DAYS IS $1,000

Settlement Settlement Operating Operating Invoice Invoice Weekday Date Weekday Date Date Amount

INVOICED MARKET SETTLEMENT

CHARGES (IMSC) Mon 11/13/04 Mon 11/08/04 11/19/2004 $1,000Mon 11/14/04 Tue 11/09/04 11/19/2004 $850Mon 11/15/04 Wed 11/10/04 11/19/2004 $900Tue 11/16/04 Thu 11/11/04 11/19/2004 $750Wed 11/17/04 Fri 11/12/04 11/19/2004 -$500Thu 11/18/04 Sat 11/13/04 11/19/2004 $800Fri 11/19/04 Sun 11/14/04 11/19/2004 $900

TOTAL $3,850

CALCULATED MARKET

SETTLEMETN CHARGES (CMSC)

Mon 11/20/04 Mon 11/15/04 $850Mon 11/21/04 Tue 11/16/04 $900Mon 11/22/04 Wed 11/17/04 $800

TOTAL $2,550

MAXIMUM ESTIMATED MARKET EXPOSURE (MEME)

Tue 11/23/04 Thu 11/18/04 $1,000Wed 11/24/04 Fri 11/19/04 $1,000Thu 11/25/04 Sat 11/20/04 $1,000Fri 11/26/04 Sun 11/21/04 $1,000Sat 11/27/04 Mon 11/22/04 $1,000

Cure Period 11/23/04 $1,000 Cure Period 11/24/04 $1,000 Cure Period 11/25/04 $1,000 Cure Period 11/26/04 $1,000 TOTAL $9,000 TOTAL ENERGY MARKET IMBALANCE EXPOSURE (EIME) $15,400

5.2.2 Transmission Service Potential Exposure (“TSPE”). Potential

exposure to non-payment associated with Transmission Service transactions is calculated under the following formula:

TSPE = ITSC + CTSC + METE

ITSC = Invoiced Transmission Service Charges (all transmission service charges that have been invoiced but not yet been paid).

CTSC = Calculated Transmission Service Charges (transmission service charges that have been calculated but not yet invoiced).

METE = Maximum Estimated Transmission Exposure

An estimate of the charges for the remainder of the Potential Exposure Window.

Calculated using the value of all charges based on reserved capacity for each confirmed Transmission Service reservation from the last date included in the CTSC calculation above to the date of the calculation of Total Potential Exposure, plus the value of all charges based on confirmed reservations for the following seventy-five (75) days from the date of the calculation of Total Potential Exposure.

METE for Network Service reservations will be

calculated by taking the highest netted Network Service invoice over the last twelve (12) months (or a lesser period if Network Service has been taken for a shorter period), multiplied by 2.5.

Participants who do not execute Attachment N of the

Tariff, therefore self providing for losses, will have losses excluded from the METE calculation.

Following are examples of Transmission Service Potential Exposure.

Example of Transmission Service Potential Exposure Calculation: ASSUMPTIONS: CURRENT DAY IS TUESDAY, NOVEMBER 23, 2004 CUSTOMER HAS PAID PREVIOUS MONTHLY INVOICE IN FULL (NOVEMBER 18) HIGHEST MONTHLY SETTLEMENT FOR LAST 12 MONTHS IS $8,000

Operating Invoice

Date Amount Invoiced Transmission Service Charges

Deleted: (the highest transmission service invoice over the last 12 months, multiplied by 2.5).

(ITSC) Already paid October Charges on November 18 $0

TOTAL $0

CALCULATED TRANSMISSION

SERVICE CHARGES (CTSC)

11/1/2004 $300 11/2/2004 $350 11/3/2004 $250 11/4/2004 $300 11/5/2004 $350 11/6/2004 $250 11/7/2004 $300 11/8/2004 $350 11/9/2004 $250

11/10/2004 $300 11/11/2004 $350 11/12/2004 $250 11/13/2004 $300 11/14/2004 $350 11/15/2004 $250 11/16/2004 $300 11/17/2004 $350 11/18/2004 $250 11/19/2004 $300 11/20/2004 $350 11/21/2004 $250

TOTAL $6,300

MAXIMUM ESTIMATED TRANSMISSION

EXPOSURE (METE) $8000 x 2.5 TOTAL $20,000

TOTAL TRANSMISSION SERVICE POTENTIAL EXPOSURE

(TSPE) $26,300

5.2.3 Calculation of Total Potential Exposure for a Market Participant. A Market Participant’s Total Potential Exposure (“TPE”) shall be the sum of the potential exposure to non-payment for Energy Imbalance Market transactions and Transmission Service transactions billed pursuant to the Tariff and may be calculated using the formula:

TPE = EIME + TSPE

Example of Total Potential Exposure Calculation:

Continuing with the previous examples in 5.2.1 and 5.2.2 the calculation would be as follows:

EIME = $15,400

TSPE = $26,300

$15,400 + $26,300 = $41,700 (TPE)

5.3 Total Potential Exposure Violations.

5.3.1 Transaction Limits. At all times, the Market Participant shall maintain its

Total Potential Exposure to a value equal to or less than its Total Credit Limit. A “Total Potential Exposure Violation” occurs when a Market Participant’s Total Potential Exposure equals or exceeds its Total Credit Limit. SPP will regularly monitor each Market Participant’s use of services and associated financial obligations. If a Market Participant’s Total Potential Exposure equals or exceeds ninety percent (90%) of its Total Credit Limit, SPP shall promptly give notice to the Market Participant. Failure by SPP to give this notice shall not relieve the Market Participant of its duties under this Section.

5.3.2 Cure of Total Potential Exposure Violation. A Market Participant shall

cure a Total Potential Exposure Violation by: (i) payment to SPP of invoiced amounts to reduce the Market Participant’s Total Potential Exposure, and/or (ii) provision of Financial Security in an amount sufficient to increase the Market Participant’s Total Credit Limit, such that after making such payments of invoiced amounts and/or providing such Financial Security, the Market Participant’s Total Potential Exposure will not exceed its Total Credit Limit. The Market Participant shall have two (2) Business Days from the date of violation to cure the violation. SPP, in its sole discretion, may determine to treat any amount tendered under (i) as an increase of Financial Security under (ii) and not as a payment to SPP.

5.3.3 Failure to Cure Total Potential Exposure Violation. A failure to cure a

Total Potential Exposure Violation as required under Section 5.3.2 is a Default. In the event of such a Default, SPP has all rights under section 7 of the Tariff and all other rights and remedies in accordance with applicable law. Without prejudice to other remedies, a Market Participant that fails timely to cure a Total Potential Exposure Violation shall be suspended from requesting any future services, including all Transmission Service and Market Services, unless and until the Market Participant’s Total Potential Exposure Violation is cured.

5.4. Excess Financial Security. In the event a Market Participant has provided

additional Financial Security under Section 5.3.2 to address a Total Potential Exposure Violation, and the Market Participant’s outstanding invoiced amounts subsequently return to levels preceding that violation such that the total amount of Financial Security exceeds the amount required under this Credit Policy, the Market Participant may request return of the excess Financial Security and SPP

shall comply with the request within two (2) Business Days; provided, that if SPP determines to review the Credit Assessment for the Market Participant due to the violation, it shall not be required to respond to the request, including return of any excess Financial Security, until two (2) Business Days after completing the new Credit Assessment.

Southwest Power Pool FINANCE COMMITTEE

Recommendation to the Board of Directors October 25, 2005

Roster: Harry Skilton, Chair Director Larry Altenbaumer Director Gary Voigt Arkansas Electric Coop Corp Trudy Harper Tenaska Doug Henry Westar Energy Michael Desselle AEP

Background The Finance Committee met on October 11, 2005 to review SPP’s proposed budget for 2006. SPP’s 2006 proposed budget includes expenditures as follows:

$000 Operating Expense $52,246 Debt Service $7,023 FERC Assessments $7,200 Capital Expenditures $13,793

SPP’s 2006 budget has also been segregated to identify costs associated with on-going operations separately from costs associated with new or developing initiatives. On-going revenues and costs are presented within the Foundation budget while other costs are presented per initiative. Revenues Op. Exp Debt Serv. FERC CapEx ($MM) ($MM) ($MM) ($MM) ($MM) Foundation $52.4 $43.9 $7.0 $7.2 $3.9 EIS $0.0 9.3 0.0 0.0 2.0 Contract 9.8 4.7 0.0 0.0 0.4 New Facility 0.0 0.6 0.0 0.0 7.5 SAS70 0.0 0.8 0.0 0.0 0.0 Recommendation The Finance Committee recommends approval of the 2006 SPP budget as submitted. Approved: Finance Committee October 11, 2005 Action Requested: Approve Recommendation

2006 BUDGET EXECUTIVE SUMMARY

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INTRODUCTION/OVERVIEW SPP’s 2006 operating budget (all cash outflows excluding capital items) totals $67MM, as compared to $55MM in 2005. SPP’s 2006 capital budget totals nearly $14MM as compared to over $18MM in 2005. SPP’s administrative fee will remain at 16¢/MWh during 2006 SPP’s 2006 budget includes additional analysis versus prior years to facilitate enhanced review and tracking during the budget year. SPP’s 2006 budget is subdivided into the activities or projects:

Foundation – Foundation activities represents revenues and expenditures associated with all functions currently performed by SPP. The Foundation budget is intended to provide a transparent view into SPP’s financial management and cost control capabilities.

EIS Market – This section separates EIS Market incremental costs directly associated with the implementation of an imbalance energy market by SPP during 2006. SPP has substantial imbedded and legacy costs associated with its EIS market that are included within the Foundation budget. Examples of these costs include existing staff working strictly on EIS implementation, principal and interest costs related to the funding of capital expenditures required to develop the EIS market.

Contract Services – Contract Services activities represents a new initiative for SPP during 2006 whereby SPP will provide services under contract to members and non-members. SPP has been awarded one contract for services and expects another to be implemented during 2006.

New Facility – New Facility activities include the capital costs associated with construction of SPP’s primary operations facility and the associated systems and furnishings required to make the facility operational. Operating costs including utilities, landscape maintenance, etc are included as well.

SAS70 – SAS70 activities include all incremental costs associated with implementing an enhanced control environment within SPP. These costs are primarily personnel, however, some minor software and capital costs are also included.

SPP will carry a revenue surplus of $9.7MM into 2006. The surplus is a byproduct of the delayed implementation of EIS market originally planned for October 2005. Due to this delay, SPP has appropriately deferred budgeted expenditures (primarily staff additions and maintenance agreements) into the 2006 budget year. SPP’s 2005 administrative fee was established prior to decisions to defer market implementation and related expenditures, resulting in revenues exceeding SPP’s net revenue requirement for the year. The surplus will serve to reduce the SPP administrative fee in 2006. Absent the surplus, SPP’s 2006 administrative rate would equal 17.68¢/MWh.


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Calculation of SPP’s 2006 administrative fee is as follows: ($000) 2006 Gross Revenue Requirement $66,469 Less: Member Fees and NERC Assessment (2,042) Miscellaneous Income (Studies and Interest) (1,751) Schedule 12 Revenue (7,200) 2006 ICT Revenue (9,760) 2006 Net Revenue Requirement (“NRR”) $45,716 Divided by 2006 Estimated Billing Determinants 258,558,000 2006 Administrative Fee $0.1768/MWh 2006 NRR less 2005 surplus $35,992 2006 Adjusted Administrative Fee $0.1392/MWh EIS Market Project Budget Summary The Company’s primary operational initiative during 2006 is implementation of the energy imbalance services market (“EIS”). Currently, the EIS is scheduled to be operational effective May 1, 2006. Once fully operational, EIS will settle imbalance energy financially across the SPP footprint. Charles River & Associates, International estimate benefits from this market exceeding $370MM over a ten-year period. Budgeted operating costs expected in 2006 are $9.3MM; SPP expects to incur capital expenditures of $2MM to complete the systems required to host the EIS. The addition of nine operations staff and two IT staff are incremental personnel costs. The operations staff additions were approved at the July 2005 SPP Board of Directors meeting. SPP anticipates hiring five operations staff during 2005 and six staff (four operations and two IT) in January 2006. Total incremental staffing costs related to EIS are estimated to be $1.1MM. SPP also forecasts increased incremental costs associated with enhancing its communications network to handle the flow of data for the EIS market and upgrading the maintenance support agreements in connection with software for the EIS market systems. Incremental costs for these components are $0.4MM and $1.8MM, respectively. Finally, SPP contracts with numerous vendors to provide project management and project support during the development of the EIS market as well as on-going services once the EIS market is operational. The bulk of these expenditures are associated with a contract terminating at the end of 2006 (put into service in 2001) whereby SPP outsourced the day-to-day operation of the commercial operating system. In aggregate, vendor services are expected to total $5.9MM during the 2006 budget year.


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Expenditures ($000) 2006 Salaries & Benefits $1,062 Travel 33 Administrative 2 Meetings 78 Communications 394 Leases & Maintenance 1,840 Outside Services 5,926 TOTAL EIS MARKET $9,335 Capital Expenditures $2,043

Contract Services Project Budget Summary SPP anticipates performing services for a fee to capitalize on our core competencies. SPP will selectively respond to requests for proposals based on the potential benefits to the SPP organization and our capability to perform the functions at a level consistent with SPP’s quality standards. SPP projects providing independent coordinator of transmission services (“ICT”) beginning in the second quarter of 2006. ICT services will require headcount increase of 34 staff. A two-year contract has been negotiated for the performance of ICT services generating annual revenue of $11.9 million. ICT revenue is projected to offset $4.9 million of SPP’s imbedded infrastructure costs resulting in a net reduction of SPP’s administrative fee of nearly 1.9¢/MWh annually. Expenditures to perform contract services are primarily associated with increased staffing to manage the workload. The chart below details the expected organization requirements to satisfy SPP’s ICT obligations.

SPP is operating under an interim agreement to provide ICT services until such time as SPP is capable of delivering the services and the customer is capable of receiving the services. Under

Executive Director (6)

Planing (7) Security Operations (9) Weekly Procurement (4) Tariff Admin (8)


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the interim agreement, the customer will reimburse SPP for all incremental costs incurred in connection with provision of ICT services.

Expenditures ($000) 2006 Salaries & Benefits $4,524 Travel 140 Administrative 18 Meetings 26 Communications 72 Leases & Maintenance 42 Outside Services 24 TOTAL CONTRACT SERVICES $4,846 Capital Expenditures $401

New Facility Project Budget Summary SPP’s current operations facility lacks security, redundancy, space, and functionality to fulfill its mission. The SPP Board of Directors approved funding for the construction of a 15,000 sq.ft. primary operations facility in the amount of $3.5MM. In addition, the 2005 budget included capital expenditures to furnish the facility with computing equipment, work space, etc. in the amount of $2.5MM. SPP acquired 10.5 acres of land in May 2005 for $300K. Construction of the building has been delayed, as the building design needed several iterations to include additional operational requirements with respect to the ICT and the EIS market. The final building design is slated for presentation to the local planning commission on October 27, 2005 with construction to begin immediately following planning commission approval. The final design encompasses 20,000 sq.ft. and is sized sufficient to house some expected growth of Contract Services staff as well as some other potential operational requirements. Hard dollar construction costs are now estimated to be $3.6MM. Build-out of the facility including data center equipment and licenses, redundant electrical and HVAC systems, and workspace is now estimated to total $3.9MM. The current timeline indicates completion of the building shell and issuance of an occupancy permit in September 2006. Build-out of the systems required to make the facility operational will require another two to three months.

Expenditures ($000) 2006 Salaries & Benefits $103 Administrative 178 Leases & Maintenance 269 Outside Services 30 TOTAL NEW FACILITY $580


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Capital Expenditures ($000) Building (excl. land) $2,6101

1 Total estimated construction costs, a portion of which may be expended during the 2005 budget year.

Furnishings 975 Systems & Software 3,902 TOTAL NEW FACILITY CAPEX $7,487

SAS70 Project Budget Summary SPP, in response to the Sarbanes Oxley certification requirements of several of its members, initiated a program to both enhance the necessary controls and undergo control audits annually. SPP has worked to fully document its internal control environment and has required additional resources to enhance its controls. During 2006 SPP projects additional resource requirements to ensure segregation of duties within its technical function.

Expenditures ($000) 2006 Salaries & Benefits $103 Administrative 400 Leases & Maintenance 41 TOTAL SAS70 $544

SALARY/EMPLOYEE BENEFITS Employee costs are the single largest component of SPP’s annual operating budget comprising nearly 45% of SPP’s annual revenue requirement. Expenditures in this area have grown commensurate with approved increases in headcount and approved salary adjustments.


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2001 2002 2003 2004 20052 2006 Headcount 110 112 116 136 155 238 Total Salary ($MM) $7.0 $7.8 $9.1 $10.4 $7.8 $19.1 Salary Rate ($MM) $8.1 $8.2 $8.9 $10.4 $12.6 $19.3 SPP’s 2005 budget approved a total of 166 positions. During the year, several positions were approved for hire by the Board of Directors and by the SPP President. The approved headcount (for hire in 2005 and 2006) is 215. This budget includes requests for 21 additional staff; bringing total approved staffing to 236 employees. Below is a reconciliation of SPP’s headcount from the original 2005 budget through the 2006 budget, as well as descriptions of the proposed new positions not previously approved and a summary organizational chart Positions approved in 2005 budget 166 Positions approved mid-year by President Release Mgr – IT 1 Communications Mgr 1 2 Part-time 4 Positions approved mid-year by BOD ICT 31 Operations 14 Total approved positions 215 New positions in 2006 Administrative 4 Corporate Affairs 1 Operations 1 Engineering 1 Regulatory 1 IT 14 Eliminated positions in 2006 Part-time -1 Net 2006 Budget Headcount 236 Administration (4) Corporate Accounting

Accountant I - Grade 5 Position supports growing workload in the accounting department for controls and focus on SPP finances. This position represents conversion of an existing part time position to a full-time Accountant I.

2 Through September 30, 2005


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Accountant II - Grade 6 Position supports SPP's desire to centralize the corporate purchasing function. Centralization would create greater efficiencies company wide as current process is a decentralized, manual process, requiring a great deal of time from many people across the company.

Human Resources/Facilities

HR Generalist I – Grade 5 Position supports SPP’s initiative to place all benefits coordination under the direction of one staff member providing enhanced communication and coordination with SPP staff regarding their benefit plans in addition to allowing current SPP HR staff additional time to dedicate towards recruiting, hiring, retention, staffing, training and staff development.

Credit Credit Analyst I – Grade 5

Position supports the implementation of the new credit policy and the associated increase in the amount of analysis and documentation that will need to be maintained.

Corporate Affairs (1) Communications

Communications Specialist II – Grade 6 Position supports the growing needs of our organization for effective communication within SPP and for its stakeholders. The present workload and reactive mode do not foster a strategic or coordinated approach to communicating with our existing and prospective stakeholders. The current daily demands repeatedly exceed our staff resources and hinder attempts at strategic or proactive activities. Frequently, the response to internal customers’ requests are postponed or denied.

Engineering (1) Tariff Studies

Engineer III – Grade 8 Position supports the initiative for the Aggregate Transmission Service Study (ATSS) required to be performed under the OATT three times annually. Study requirements will increase as the complexity of the study develops. This position will be fully billable to the customers of the ATSS.

IT Applications (8) Summary

Positions support the following projects/initiatives: the Entergy ICT, the Joint Operating Agreement (JOA) with MISO, the Market Monitoring Project, the Implementation of a


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Controlled Environment at SPP, and the new functionality being added to the EIS Market systems. Specifics: 1.50 FTE Entergy ICT

[0.5 FTE IT Specialist I (Grade 6) + 1.0 FTE IT Specialist II (Grade 7)] 1.00 FTE JOA systems & Seams Agreements

[1.0 FTE IT Specialist III (Grade 8)] 2.00 FTE Implementation of Controlled Environment (Separation of Duties)

[2.0 FTEs - IT Specialist II (Grade 7)] 2.50 FTE Implementation of EIS Market (Existing + New Functionality)

[2.0 FTEs - IT Specialist II (Grade 7) + 0.5 FTE - Supervisor, EMS/Reliability Support (Grade 9)]

1.00 FTE Support Reliability Function Enhancements [0.5 FTE - Supervisor, EMS/Reliability Support (Grade 9) + 0. 5 FTE IT Specialist I (Grade 6)]

_______ 8.00 FTE

IT Infrastructure (6) Summary

Positions support the following projects/initiatives: the Entergy ICT, the Implementation of a Controls Environment at SPP, the new functionality being added to the EIS Market systems, and the addition of the New Facility. Specifics: 1.75 FTE Entergy ICT

[1.0 FTE IT Specialist II (Grade 7) + 0.5 FTE IT Specialist I (Grade 6) + 0.25 FTE Security Analyst I (Grade 6)]

1.75 FTE Implementation of Controls Environment [1.25 FTE IT Specialist II (Grade 7) + 0.25 FTE IT Specialist I (Grade 6) + 0.25 FTE Security Analyst I (Grade 6)]

0.25 FTE Implementation of EIS Market [0.25 FTE IT Specialist II (Grade 7)]

2.25 FTE New Facility [0.5 FTE IT Specialist II (Grade 7) + 1.25 FTE IT Specialist I (Grade 6) + 0.5 FTE Security Analyst I (Grade 6)]

_______ 6.00 FTE


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Operations (1) Operations Engineering

Operations Engineer I – Grade 7 Position supports the increased volume of system impact study requests for firm reservations primarily in the short-term (weekly and daily) requests. The recent filing of Attachment AC of the SPP OATT will result in increased volume of requests due to improved timing requirements and increased awareness among market participants of available re-dispatch options.

Regulatory (1) Staff Attorney – Grade 8

Position supports the following continuing and new initiatives: • Generator Interconnection • Formula Rates • EIS Market Implementation • Energy Bill • Entergy ICT

There is growing evidence that justification already exists and will continue to grow for additional legal support in SPP’s regulatory area. Legal and consultants fees for the period 1/1/05 through 7/20/05 has been $624K as compared to $363K during the same period in 2004. Additionally, the number of cases pending as of the end of the second quarter 2005 stood at 21 compared to seven at that point in 2004.

CommunicationsCurrent Employees: 3Proposed Employees: 1

TrainingCurrent Employees: 6

Customer ServiceCurrent Employees: 5

Legal & Corporate AffairsCurrent Employees: 1

Contract ServicesExecutive Directror: 1, Current Employees: 1Unfilled positions: 29

ComplianceDirector: 1Current Employees: 1

Market DevelopmentDirector: 1Current Employees: 5Unfilled positions: 3

AccountingDirector: 1; Current Employees: 9, 1 part timeUnfilled positions: 4Proposed Employees: 3

Human Resources, Facilities, AdministrationCurrent Employees: 6Proposed employees: 1

Finance

ApplicationsCurrent Employees: 24Unfilled positions: 1Proposed Employees: 8

InfrastructureCurrent Employees: 11Unfilled positions: 1Proposed Employees: 6

Telecommunications/SecurityCurrent Employees: 7Unfilled positions: 1

Change ManagementCurrent Employees: 2

Information TechnologyDirectors: 2

PlanningCurrent Employees: 6

Tariff StudiesCurrent Employees: 7Unfilled positions: 1Proposed Employees: 1

TransmissionCurrent Employees: 4Unfilled positions: 1

RegulatoryDirector: 1Current Employees: 2, 1 part timeProposed Employees: 1

Engineering & RegulatoryDirector: 1Administrative: 1

Market OperationsCurrent Employees: 7Unfilled positions: 2Proposed employees: 1

Operations EngineeringCurrent Employees: 6Unfilled positions: 3Proposed Employees: 3

EMS Applications & Network ModelsCurrent Employees: 5Unfilled positions: 1Proposed Employees: 2

SchedulingCurrent Employees: 8

ReliabilityCurrent Employees: 7Unfilled positions: 2Proposed Employees: 2

Tariff AdministrationCurrent Employees: 7

OperationsDirector: 1

ExecutiveCurrent Employees: 7

The SPP Human Resources Committee is currently reviewing the benefits of implementing a performance compensation plan beginning in 2005. The plan, as currently designed, would compensate SPP employees for their individual contribution to SPP’s overall corporate performance. Payouts under the plan are expected to equal approximately15% of year-end


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salaries. Cash outflows for performance compensation earned in 2006 would occur in February 2007. Medical healthcare insurance premium rates have been budgeted to remain flat as SPP expects to benefit from its internal wellness initiatives and increased group size. Total premiums will increase in tandem with the increase in headcount. SPP currently splits healthcare premiums with employees using an 80%/20% ratio. The HR Committee reviewed SPP’s benefit programs in 2005 and has not recommended changes to healthcare funding. Funding levels for SPP’s defined benefit retirement plan and retiree healthcare are also budgeted to remain flat. SPP obtains an actuarial report in mid May that is utilized by the HR Committee to establish the annual funding level. Funding for SPP’s matching contribution to the 401(k) plan is estimated at 4.5% of salary. Compensation of SPP’s independent directors is forecast to total $345K in 2006. SPP recently approved additional compensation for directors related to attendance at meetings where the director is not a member of the meeting group or at other required meetings. Better meeting planning has resulted in fewer board level committee meetings in 2005 versus 2004 supporting a reduced estimate for director compensation compared with the 2005 budget ($390K). EMPLOYEE TRAVEL Expenditures in this category include hotel, airfare, dining, and entertainment expenditures incurred by SPP employees in the performance of their assigned duties. SPP responsibilities related to participation and facilitation of SPP working groups and task forces, as well as NERC activities, necessitates substantial travel. 2005 actual travel expenses are projected to equal 94% of the 2005 budget. 2006 travel, exclusive of travel expenses related to ICT services, is forecast to exceed 2005’s budget by 10% as a result of additional meetings in advance of EIS implementation and higher fares resulting from recent spikes in fuel prices. SPP will remain diligent in managing travel expenditures in the most efficient manner possible. ADMINISTRATIVE Insurance includes standard insurance coverage to protect the company, its employees and directors, and the membership from unforeseen events. SPP anticipates increasing coverage limits for director & officer liability to address concerns voiced by several members of the board. We anticipate purchasing an excess layer above SPP’s existing D&O program designed to provide coverage in the event SPP is unable to fully indemnify the insureds. Below is a summary of SPP’s insurance programs and premiums: Limit ($000) Premium ($000) ’05 Premium General Liability $1,000 $42 $29 Excess Liability (E&O) $75,000 $873 $670 D&O Liability $50,000 $125 $51 Audit expenses in 2006 include $45K for the annual audit of SPP’s financial statements and an additional $400K to cover the costs associated with engaging a type-II audit of SPP’s control environment. These expenditures are in line with SPP’s experience during 2005.


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SPP has reclassified its budgeting for small equipment and software purchases to the Administrative category from the Capital Expenditures category to more properly budget in line with GAAP reporting. The 2006 budget for Administrative expenses includes $226K in these expenditures. Subscriptions include costs associated with maintaining a credit rating with Standard & Poor’s. SPP will also subscribe to a credit reporting service to facilitate ongoing review and monitoring of creditworthiness of customers of the tariff. ASSESSMENTS & FEES SPP’s NERC assessment is expected to increase in 2006 according to NERC projections; totaling $834K. Additionally, SPP will fund its pro rata share of the costs associated with upgrading the NERC IDC. This cost is expected to total $108K. SPP, as a federally jurisdictional regional transmission organization, is assessed a portion of the operating costs of the Federal Energy Regulatory Commission. SPP’s share of this assessment is based upon the total assessable energy within SPP’s footprint as a percentage of the assessable energy subject to the jurisdiction of the FERC. SPP estimates its share of FERC’s assessment will total $7.2MM. SPP will recover this cost via collections under schedule 12 of the SPP OATT. MEETINGS This item covers the costs associated with SPP hosting meetings. Following is a listing of the various groups for which SPP typically incurs meeting expenses.

• Bandwidth WG • Board of Directors/Members Committee • Coordinated Black Start TF • Corporate Governance Committee • Credit TF • Critical Infrastructure Protection WG • Engineering Task Forces • Finance Committee • Generation WG • Human Resources Committee • Market Implementation TF • Market WG • Markets and Operations Policy Committee • Market Monitoring and Market Power

Mitigation TF • Model Development TF

• NERC CIPC • Operating Reliability WG • Operating Reserve TF • Operational Control TF • Operational Model Development WG • Operations Data WG • Operations Training WG • Regional Planning Summits • Regional State Committee • Regional Tariff WG • Settlements TF • Strategic Planning Committee • System Protection and Control WG • Training Courses • Transmission WG • Voltage & Reactive Management TF

COMMUNICATIONS Communication networks and capability are crucial to SPP in the performance of its required functions. SPP’s system models and state estimator depend on the exchange of timely and reliable information across thousands of data points. SPP ensures communication paths with


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its membership via a dedicated primary private frame-relay network. A separate network provided by another vendor further supports redundancy for this network. Expenditures for this network approximate $1.5MM. SPP also utilizes a high availability fiber network that facilitates transfer of information, primarily related to EIS, across the internet. The fiber network provides aggregate OC48 capacity with DS3 connections to members and ISPs (allowing 600 mega bytes per second information transfer between SPP’s corporate and DR sites) to ensure rapid transmission of information to SPP’s systems and to customers. SPP further utilizes two internet service providers (primary and secondary) to ensure availability through all but the most extreme events. Fiber expenditures cost $840K per year. Other communication expenditures include local and long distance telephone service, including teleconference capability, web casting services, and employee communication capability. LEASES AND MAINTENANCE Increases in staffing have resulted in increased office space requirements for SPP. Currently the Company leases space under a long-term lease expiring in 2011. SPP has negotiated to bring on-line approximately 5,000 additional square feet of space in late 2005. SPP is also tactically re-working its workspace environment to ensure efficient utilization of all available space. Total office lease for 2006 is $679K The market system maintenance agreement was previously budgeted for implementation in 2005 as the EIS market system was brought online. Delays in implementing the EIS market have allowed SPP to defer costs associated with maintenance support of its market system into 2006. The maintenance agreement provides support to the critical functions supported by the EMS network applications, tariff support applications, and the market operations system. The agreement for 2006 will cover critical functions, regardless of the application or database causing the problem, and will have defined priority-based service levels like the prototype agreement tested in 2001. The agreement cost provides for designated, focused support staff, the ability to contact the support staff any time of the day or night, and replication of the SPP environment at the vendor to duplicate and resolve problems. OUTSIDE SERVICES SPP obtains third party expertise to assist in the deployment of its services in a reliable and cost efficient manner. Primary among these services are the management and support of its commercial operations system required in the operation of the EIS market. SPP has also engaged consultants to monitor its markets in an impartial and independent manner. Finally, SPP has engaged a consultant to provide substantial project management assistance to ensure milestones are met as SPP moves to implement its EIS market on May 1, 2006. Total consulting services expenditures budgeted for 2006 dedicated to EIS market total $6.7MM. SPP utilizes numerous software applications specific to performance of electric utility services. These complex applications are further customized to meet the special and specific requirements of SPP’s members and customers. SPP engages consultants, primarily the providers of the applications, to ensure the systems remain updated for known fixes and


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upgraded for needed functionality. Systems requiring these consultants are the EMS (supports control area, reliability coordination, and tariff administration operations); OASIS (provides required transmission service interface to the transmission customer for all activities related to requests for transmission service); and RTO-SS (regional and control area transmission service scheduling system). Expenditures for these services fluctuate based on the needs required by SPP working groups and committees as well as enhancements requested by SPP operations staff. SPP expects these operating expenditures to equal just under $1.4MM during 2006. REGIONAL STATE COMMITTEE The RSC prepared a two-year budget forecasting its administrative costs. These costs are primarily reimbursements for travel and meeting expenditures of individual RSC members and their delegates. CAPITAL EXPENDITURES Significant items in the Capital Budget include: Imbalance Market – Additional capital expenditures are forecast for 2006 to complete the EIS market platform and implement on May 1, 2006. These expenditures are summarized below:

$000 Market Monitoring System $140 Real Time System Enhancements 1,903

Total $2,043 Primary Operations Center – This project will establish a stand-alone operations facility to house SPP’s critical operations, including its coordination center and data center. This site will be able to function completely independently of the main SPP office.

$000 New Facility Shell $3,585 Data Center Assets 3,902

Total $7,487 Maintenance CapEx represents capital expenditures required to maintain SPP’s existing equipment and facilities at their current levels. Components of these items are summarized below:

• Software Licenses to support functions of SPP. Total: $1.1MM. • Hardware includes PCs for existing and new employees; remodeling costs to provide

workspace for staff; security items (firewalls, surveillance equipment); and telephone equipment. Total: $2.4MM.

Capital Funding Account, to fund capital projects of the organization, was established in 2004 with an initial balance of $28.3MM. Current projections indicate the balance of this account will be depleted in October 2006. SPP intends to replenish the balance in this


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account with additional debt financing in the amount of $25MM. Below is a summary of activity in this account $000 Balance January 1, 2004 $28,300 Less: Capital Expenditures 2004 -$7,219 Plus: Interest Earned 2004 $217 Balance December 31, 2004 $21,298 Less: Capital Expenditures YTD 7/2005 -$5,175 Plus: Interest Earned YTD 8/2005 $399 Balance September 30, 2005 $16,522 DEBT PAYMENTS Senior Notes due 2008: SPP will make a $5MM principal payment on its 2008 Senior Notes in March 2006, reducing the remaining principal balance to $10 million; interest costs during the year will total $828K. Senior Notes due 2011: SPP will make interest payments on these notes totaling $1.2MM; outstanding principal balance will remain at $25MM. Beginning June 25, 2007 and annually thereafter through June 25, 2011, SPP will be required to make principal payments in the amount of $5MM. Revolving Line of Credit: SPP maintains an $8MM revolving credit facility. No advances are anticipated under this facility during 2006.

2006 Budget Draft Overview - Finance Committee

2005-06 Change 2005-06 % Change

2003 Actual 2004 Actual 2005 Budget 2006 Budget Draft from Budget from Budget

Tariff Administration Fees 27,451 38,555 40,391 41,369 979 + 2%Member Fees 0 1,118 1,100 1,100 0 + 0%NERC Assessment 0 690 709 942 233 + 33%FERC Fee Assessment 0 0 7,200 7,200 0 + 0%Contract Services Revenue 0 0 0 9,760 9,760 + 0%Miscellaneous Income 2,559 1,503 1,080 1,751 671 + 62%INCOME 30,010 41,865 50,480 62,122 11,643 + 23%

Surplus Carryforward 0 0 4,000 9,724

Salaries & Benefits 12,005 14,499 19,250 29,205 9,955 + 52%Travel 583 613 688 872 183 + 27%Administrative 1,007 1,109 1,939 2,572 632 + 33%Assessments & Fees 623 692 7,909 8,142 233 + 3%Meetings 191 334 399 458 59 + 15%Communications 1,107 1,198 3,159 2,666 (493) - 16%Leases & Maintenance 1,426 2,657 3,565 4,864 1,299 + 36%Outside Services 4,639 7,480 8,553 10,218 1,665 + 19%Regional State Committee 0 3 1,423 449 (974) - 68%Debt Service 1,875 1,875 7,414 7,039 (375) - 5%

OPERATING EXPENSES 23,456 30,459 54,300 66,485 12,185 + 22%

SURPLUS OF INCOME OVER EXPENSES

6,554 11,406 (3,820) (4,362)

253,489 258,558

17.51 17.69 0.18 + 1%

15.93 16.00 0.07 + 0%

Capital Expenditures 1,545 1,545 18,300 13,793 (4,507) - 25%

Billing Determinants

Cost per MWh (in cents) before using PY surplus carryforward

Cost per MWh (in cents)

1

2006 Foundation & Project Budgets

$Thousands Foundation EIS Market ICT New Facility SAS70 TOTAL- - -

Tariff Administration Fees 41,369 - - - - 41,369 Member Fees 1,100 - - - - 1,100 NERC Assessment 942 - - - - 942 FERC Fee Assessment 7,200 - - - - 7,200 Contract Services Revenue - - 9,760 - - 9,760 Miscellaneous Income 1,751 - - - - 1,751

INCOME 52,363 - 9,760 - - 62,122

Salaries & Benefits 23,307 1,062 4,405 103 328 29,205 Travel 699 33 140 - - 872 Administrative 1,974 2 18 178 400 2,572 Assessments & Fees 8,142 - - - - 8,142 Meetings 355 78 26 - - 458 Communications 2,200 394 72 - - 2,666 Leases & Maintenance 2,674 1,840 42 267 41 4,864 Outside Services 4,238 5,926 24 30 - 10,218 Regional State Committee 449 - - - - 449 Interest on Deposits - - - - - -Debt Service 7,039 - - - - 7,039

EXPENSES 51,076 9,335 4,727 578 769 66,485

Headcount 186 11 34 2 3 236

Capital Expenditures 3,862 2,043 401 7,487 - 13,793

2006 Budget Comparisons

Budget '06 vs. Budget '06 vs. Budget '05 vs.2006 Budget 2005 Budget Budget '05 2006 Budget 2005 Projection Projection '05 2005 Budget 2005 Projection Projection '05 2004 Actual

Revenues (000)Tariff Administration Fees 41,369 40,391 979 41,369 44,449 (3,080) 40,391 44,449 (4,059) 38,555 Member Fees 1,100 1,100 0 1,100 1,068 32 1,100 1,068 32 1,078 NERC Assessment 942 709 233 942 709 234 709 709 0 690 FERC Assessment 7,200 7,200 0 7,200 5,868 1,332 7,200 5,868 1,332 0 Contract Services Revenue 9,760 0 9,760 9,760 0 9,760 0 0 0 0 Miscellaneous Income 1,751 1,080 671 1,751 2,469 (718) 1,080 2,469 (1,389) 1,543

TOTAL REVENUES 62,122 50,480 11,643 62,122 54,563 7,559 50,480 54,563 (4,084) 41,865

SURPLUS CARRYFORWARD 9,724 4,000 5,724 9,724 6,000 3,724 4,000 6,000 (2,000) 0

TOTAL REVENUE PLUS SURPLUS 71,846 54,480 17,367 71,846 71,846 54,480 54,480

Expenses (000)Salaries & Benefits

Salaries 18,960 13,216 5,745 18,960 12,166 6,794 13,216 12,166 1,050 10,451 Benefits 6,601 5,281 1,320 6,601 4,425 2,176 5,281 4,425 856 3,486 Board compensation 345 390 (45) 345 318 27 390 318 72 292 Performance compensation plan 2,808 0 2,808 2,808 990 1,818 0 990 (990) 0 Employee expenses 491 364 127 491 339 152 364 339 25 270 Total Salaries & Benefits 29,205 19,250 9,955 29,205 18,238 10,967 19,250 18,238 1,012 14,499

Travel 872 688 183 872 632 240 688 632 56 613

AdministrativeInsurance 1,095 875 220 1,095 847 248 875 847 28 662 Small equipment & software 226 0 226 226 0 226 0 0 0 0 Audits 445 450 (5) 445 504 (59) 450 504 (54) 52 General & office expenses 806 615 191 806 568 238 615 568 47 395 Total Administrative 2,572 1,939 633 2,572 1,919 653 1,939 1,919 20 1,109

Assessments & FeesNERC annual assessment 834 709 125 834 709 125 709 709 (0) 692 NERC IDC upgrade assessment 108 0 108 108 0 108 0 0 0 FERC assessment 7,200 7,200 0 7,200 7,200 0 7,200 7,200 0 0 Total Assessments & Fees 8,142 7,909 233 8,142 7,909 233 7,909 7,909 (0) 692

Meetings 458 399 59 458 366 92 399 366 33 334

Communications 3

2006 Budget Comparisons

Budget '06 vs. Budget '06 vs. Budget '05 vs.2006 Budget 2005 Budget Budget '05 2006 Budget 2005 Projection Projection '05 2005 Budget 2005 Projection Projection '05 2004 Actual

Communications backbone 854 849 5 854 420 434 849 420 429 77 Wide area communications 1,510 1,970 (459) 1,510 970 540 1,970 970 1,000 893 Other 302 341 (39) 302 621 (319) 341 621 (280) 228 Total Communications 2,666 3,159 (493) 2,666 2,011 655 3,159 2,011 1,148 1,198

Leases & MaintenanceLeases 808 746 62 808 703 105 746 703 43 763 Hardware maintenance 801 464 337 801 181 620 464 181 283 200 Software maintenance 3,255 2,354 901 3,255 1,450 1,805 2,354 1,450 904 1,698 Total Leases & Maintenance 4,864 3,565 1,299 4,864 2,334 2,530 3,565 2,334 1,231 2,660

Outside ServicesLegal 1,260 840 420 1,260 1,170 90 840 1,170 (330) 916 Information Technology 2,315 1,762 554 2,315 1,487 828 1,762 1,487 275 1,025 Market Design & Analysis 5,926 5,049 876 5,926 4,993 933 5,049 4,993 56 4,206 Other consulting 717 902 (185) 717 1,214 (497) 902 1,214 (312) 1,333 Total Outside Services 10,218 8,553 1,665 10,218 8,864 1,354 8,553 8,864 (311) 7,480

Regional State CommitteeOperating expenses 249 223 26 249 302 (53) 223 302 (79) 3 Cost benefit study 200 1,200 (1,000) 200 670 (470) 1,200 670 530 0 Total Regional State Committee 449 1,423 (974) 449 972 (523) 1,423 972 451 3

Debt ServiceLoan interest 2,039 2,414 (375) 2,039 2,594 (555) 2,414 2,594 (180) 2,160 Loan principal 5,000 5,000 0 5,000 5,000 0 5,000 5,000 0 0 Total Debt Service 7,039 7,414 (375) 7,039 7,594 (555) 7,414 7,594 (180) 2,160

TOTAL OPERATING EXPENSES 66,485 54,300 12,186 66,485 50,839 15,646 54,300 50,839 3,460 30,747

BILLING DETERMINANTS 258,558 253,489 5,070 258,558 258,558 253,489 253,489

Gross Cost per MWh (in cents) 19.76 17.51 2.25 19.76 19.76 17.51 17.51 (before using surplus carryforward)

Cost per MWh (in cents) 16.00 15.93 0.07 16.00 16.00 15.93 15.93

Depreciation & AmortizationDepreciation 7,404 4,800 2,604 7,404 2,531 4,872 4,800 2,531 2,269 5,280 Amortization 41 81 (40) 41 82 (41) 81 82 (1) 61 Total Depreciation/Amortization 7,444 4,881 2,563 7,444 2,613 4,831 4,881 2,613 2,268 5,341

4

Foundation

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total


Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2006 Total

33 48 33 28 55 22 24 33 23 23 13 13 348 11 11 11 11 11 11 11 11 11 11 11 11 136

1,138 1,138 1,139 1,140 1,143 1,144 1,144 1,143 1,142 1,142 1,142 1,142 13,695 126 126 126 126 126 124 127 127 127 127 127 127 1,515 17 17 17 17 17 17 17 17 17 17 17 17 209 47 47 47 47 47 47 47 47 46 46 44 44 553

182 182 182 182 182 183 183 183 183 183 183 183 2,191 54 54 54 54 54 54 54 54 54 54 54 54 652 75 75 75 74 74 73 71 69 66 64 61 60 836 71 71 71 71 71 75 75 75 75 75 75 75 879 93 93 93 93 93 93 93 93 93 93 93 93 1,116 42 42 42 42 42 42 42 42 42 42 42 42 504 70 - - - - 5 - - - - - - 75 96 - - - - 12 - - - - - - 108 7 2 1 1 1 1 1 1 1 1 1 1 14

18 6 1 1 1 1 1 1 1 1 1 1 34 32 13 15 40 101 34 32 4 15 36 0 25 345 8 8 8 8 8 8 8 8 8 8 8 8 96

2,119 1,933 1,915 1,935 2,026 1,946 1,930 1,908 1,904 1,924 1,873 1,897 23,307

Foundation 5


Tariff Administration Fees - - - - - - - - - - - - -Member Fees - - - - - - - - - - - - -NERC Assessment - - - - - - - - - - - - -FERC Fee Assessment - - - - - - - - - - - - -Contract Services Revenue - - - - - - - - - - - - -Miscellaneous Income - - - - - - - - - - - - -

INCOME - - - - - - - - - - - - -


Salaries & BenefitsStaff Additions 6 6 6 6 6 6 6 6 6 6 6 6 66 Staff Additions 11 11 11 11 11 11 11 11 11 11 11 11 132 Staff Additions 5 5 5 5 5 5 5 5 5 5 5 5 66 Existing Salaries 10 10 10 10 10 10 10 10 10 10 10 10 117 Staff Additions 11 11 11 11 11 11 11 11 11 11 11 11 132 Existing Salaries 15 15 15 15 15 15 15 15 15 15 15 15 183 Dental Insurance 1 1 1 1 1 1 1 1 1 1 1 1 8 Dental Insurance 1 1 1 1 1 1 1 1 1 1 1 1 6 Health Insurance 7 7 7 7 7 7 7 7 7 7 7 7 79 Health Insurance 6 6 6 6 6 6 6 6 6 6 6 6 66 Medicare (1.45%) Total 0 0 0 0 0 0 0 0 0 0 0 0 6 Medicare (1.45%) Total 0 0 0 0 0 0 0 0 0 0 0 0 4 Performance Compensation Total 9 9 9 9 9 9 9 9 9 9 9 9 104 Savings Plan (4.5%) 3 3 3 3 3 3 3 3 3 3 3 3 31 Social Security (6.2%) 3 3 3 3 3 3 3 3 3 3 3 3 31 Hiring Expense 30 - - - - - - - - - - - 30 EIS Salary & Benefit Total 116 86 86 86 86 86 86 86 86 86 86 86 1,062

EIS Market



EIS Market


TravelMarkets:Market Design & Analysis 2 1 2 2 1 1 2 1 2 2 1 1 19 Markets:Market Monitoring 1 1 2 - 1 3 - 1 3 - 1 3 14 EIS Travel Total 3 2 4 2 2 4 2 2 5 2 2 3 33 AdministrativeDues - - - - - - - - - - - 1 1 Dues - - - - 1 - - - - - 1 - 1 EIS Administrative Total - - - - 1 - - - - - 1 1 2

Assessments & Fees -

MeetingsMarket Implementation TF 3 3 3 3 3 3 - - - - - - 18 Market WG 3 3 3 3 3 3 3 3 3 3 3 3 30 Training - - - - - - - - - - - 1 1 Training:Market Training Follow-Up - - - - - 3 3 3 3 3 - - 15 Training:Market Training Follow-Up - - - - - 3 3 3 3 3 - - 14 EIS Meetings Total 6 6 6 6 6 11 8 8 8 8 3 3 78

CommunicationsSPPNET, Primary 13 13 13 13 13 13 13 13 13 16 16 16 164 SPPNET, Primary 3 3 3 3 3 3 3 3 3 4 4 4 41 SPPNET, Secondary 5 5 5 5 5 5 5 5 5 7 7 7 70 SPPNET, Secondary 1 1 1 1 1 1 1 1 1 2 2 2 17 OATI SPPNET Connection Fee 0 0 0 0 0 0 0 0 0 0 0 0 2 OATI SPPNET Connection Fee 0 0 0 0 0 0 0 0 0 0 0 0 0 Internet:Internet Services:Primary Intern 4 4 4 4 4 4 4 4 4 4 4 4 52 Internet:Internet Services:Secondary Inte 4 4 4 4 4 4 4 4 4 4 4 4 45 E-Mail Internet services 0 0 0 0 0 0 0 0 0 0 0 0 3 EIS Communications Total 31 31 31 31 31 31 31 31 31 38 38 38 394


EIS Market


Leases & MaintenanceMAINTENANCE - Software:Software - O 1,323 - - 35 160 - 19 - - - - 300 1,837 MAINTENANCE - Software:Software - - 2 - - - - - 1 - - - 3 EIS Lease & Maintenance Total 1,323 - 2 35 160 - 19 - 1 - - 300 1,840

Outside ServicesProduction Costs 349 349 349 349 349 349 349 349 349 349 349 349 4,192 Project assistance 147 147 147 147 147 147 - - - - - - 883 Economist Vendor 50 50 50 300 50 50 50 50 50 50 50 50 850 EIS Outside Services Total 547 547 547 797 547 547 399 399 399 399 399 399 5,926

Regional State Committee 0 0 0 0 0 0 0 0 0 0 0 0 0

Interest on Deposits 0 0 0 0 0 0 0 0 0 0 0 0 0

Debt Service 0 0 0 0 0 0 0 0 0 0 0 0 0

EXPENSES 2,024 672 675 957 831 679 546 527 531 533 528 830 9,334


Tariff Administration Fees - - - - - - - - - - - - -Member Fees - - - - - - - - - - - - -NERC Assessment - - - - - - - - - - - - -FERC Fee Assessment - - - - - - - - - - - - -Contract Services Revenue 400 400 450 450 450 952 952 998 998 998 998 1,057 9,103 Miscellaneous Income - - - - - - - - - - - - -

INCOME 400 400 450 450 450 952 952 998 998 998 998 1,057 9,103

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2006 TotalSalaries & BenefitsContinuing Education - - - 3 - - 3 - - 3 - - 8 Continuing Education - - - - - 3 3 3 3 3 3 3 18 Continuing Education - - - - - 3 - - 3 - - - 5 Continuing Education - - - - - 3 - - 3 - - 3 8 Continuing Education - - - - - 3 - - - 3 - - 5 Dental Insurance 0 0 0 0 0 0 0 0 0 0 0 0 3 Dental Insurance 1 1 1 1 1 1 1 1 1 1 1 1 8 Dental Insurance 1 1 1 1 1 1 1 1 1 1 1 1 9 Dental Insurance 0 0 0 0 0 0 0 0 0 0 0 0 4 Dental Insurance 1 1 1 1 1 1 1 1 1 1 1 1 9 Existing Salaries 15 15 15 15 15 15 15 15 15 15 15 15 175 Existing Salaries 8 8 8 8 8 8 8 8 8 8 8 8 98 Health Insurance 3 3 3 3 3 3 3 3 3 3 3 3 37 Health Insurance 7 7 7 7 7 7 7 7 7 7 7 7 87 Health Insurance - - - - - - - - - - - - -Health Insurance 4 4 4 4 4 4 4 4 4 4 4 4 49 Health Insurance 8 8 8 8 8 8 8 8 8 8 8 8 99 Medicare (1.45%) 0 0 0 0 0 0 0 0 0 0 0 0 5 Medicare (1.45%) 1 1 1 1 1 1 1 1 1 1 1 1 8 Medicare (1.45%) 1 1 1 1 1 1 1 1 1 1 1 1 11

Contract Services



Contract Services


Medicare (1.45%) 0 0 0 0 0 0 0 0 0 0 0 0 5 Medicare (1.45%) 1 1 1 1 1 1 1 1 1 1 1 1 10 Merit Increase 1 1 1 1 1 1 1 1 1 1 1 1 13 Merit Increase 2 2 2 2 2 2 2 2 2 2 2 2 23 Merit Increase 2 2 2 2 2 2 2 2 2 2 2 2 26 Merit Increase 1 1 1 1 1 1 1 1 1 1 1 1 13 Merit Increase 2 2 2 2 2 2 2 2 2 2 2 2 28 Performance Compensation 4 4 4 4 4 4 4 4 4 4 4 4 48 Performance Compensation 7 7 7 7 7 7 7 7 7 7 7 7 87 Performance Compensation 10 10 10 10 10 10 10 10 10 10 10 10 114 Performance Compensation 4 4 4 4 4 4 4 4 4 4 4 4 50 Performance Compensation 9 9 9 9 9 9 9 9 9 9 9 9 104 Savings Plan (4.5%) 1 1 1 1 1 1 1 1 1 1 1 1 14 Savings Plan (4.5%) 2 2 2 2 2 2 2 2 2 2 2 2 26 Savings Plan (4.5%) 3 3 3 3 3 3 3 3 3 3 3 3 34 Savings Plan (4.5%) 1 1 1 1 1 1 1 1 1 1 1 1 15 Savings Plan (4.5%) 3 3 3 3 3 3 3 3 3 3 3 3 31 Social Security (6.2%) 2 2 2 2 2 2 1 1 1 1 1 1 16 Social Security (6.2%) 3 3 3 3 3 3 3 3 3 3 3 3 36 Social Security (6.2%) 4 4 4 4 4 4 4 4 4 4 4 4 47 Social Security (6.2%) 2 2 2 2 2 2 2 2 2 2 2 2 20 Social Security (6.2%) 4 4 4 4 4 4 4 4 4 4 4 4 43 Staff Additions 12 12 12 12 12 12 12 12 12 12 12 12 145 Staff Additions 40 40 40 40 40 40 40 40 40 40 40 40 479 Staff Additions 63 63 63 63 63 63 63 63 63 63 63 63 761 Staff Additions 28 28 28 28 28 28 28 28 28 28 28 28 331 Staff Additions 58 58 58 58 58 58 58 58 58 58 58 58 695 Hiring Expense 10 - - - - - - - - - - - 10 Hiring Expense 15 - - - - - - - - - - - 15 Hiring Expense 20 - - - - - - - - - - - 20 Hiring Expense 10 - - - - - - - - - - - 10


Contract Services


Hiring Expense 20 - - - - - - - - - - - 20 Relocation Expense 12 - - - - - - - - - - - 12 Relocation Expense 36 - - - - - - - - - - - 36 Relocation Expense 48 - - - - - - - - - - - 48 Relocation Expense 24 - - - - - - - - - - - 24 Relocation Expense 48 - - - - - - - - - - - 48 Staff Additions 11 11 11 11 11 11 11 11 11 11 11 11 132 Staff Additions 5 5 5 5 5 5 5 5 5 5 5 5 66 Dental Insurance 0 0 0 0 0 0 0 0 0 0 0 0 4 Health Insurance 3 3 3 3 3 3 3 3 3 3 3 3 40 Medicare (1.45%) Total 0 0 0 0 0 0 0 0 0 0 0 0 3 Performance Compensation Total 2 2 2 2 2 2 2 2 2 2 2 2 30 Savings Plan (4.5%) 1 1 1 1 1 1 1 1 1 1 1 1 9 Social Security (6.2%) 1 1 1 1 1 1 1 1 1 1 1 1 12 Hiring Expense 10 - - - - - - - - - - - 10 Contract Services Salary & Benefits Total 596 343 343 345 343 353 347 345 350 350 345 347 4,405

TravelContract Services 20 20 10 10 10 10 10 10 10 10 10 10 140 Contract Services Travel Total 20 20 10 10 10 10 10 10 10 10 10 10 140

AdministrativeHardware-ICT 2 - - - - - - - - - - - 2 Hardware-ICT 6 - - - - - - - - - - - 6 Hardware-ICT 2 - - - - - - - - - - - 2 Hardware-ICT 1 - - - - - - - - - - - 1 Software-ICT 6 - - - - - - - - - - - 6 Software-ICT 3 - - - - - - - - - - - 3 Contract Services Administrative Total 18 - - - - - - - - - - - 18


Contract Services


Assessments & Fees

MeetingsICT - - - 2 - - 10 - 2 10 - 2 26 Contract Services Meetings Total - - - 2 - - 10 - 2 10 - 2 26

CommunicationsO&M:Cellular Phone Services-ICT 1 1 1 1 1 1 1 1 1 1 1 1 7 ICT Circuit to Entergy - PB 5 5 5 5 5 5 5 5 5 5 5 5 61 O&M:Wireless Modem Services-ICT 0 0 0 0 0 0 0 0 0 0 0 0 3 Contract Services Communications Total 6 6 6 6 6 6 6 6 6 6 6 6 72

Leases & MaintenanceLeases:Office Space, New Orleans 4 4 4 4 4 4 4 4 4 4 4 4 42 Contract Services Lease & Maintenance Total 4 4 4 4 4 4 4 4 4 4 4 4 42

Outside ServicesContract Services 2 2 2 2 2 2 2 2 2 2 2 2 24 Contract Services Outside Services Total 2 2 2 2 2 2 2 2 2 2 2 2 24

Regional State Committee

Interest on Deposits

Debt Service

EXPENSES 645 374 364 369 364 374 379 366 373 381 366 371 4,727

New FacilityJan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total


INCOME - - - - - - - - - - - - -

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2006 TotalSalaries & BenefitsStaff Additions - - - - - 4 4 4 4 4 4 4 30 Staff Additions - - - - - 4 4 4 4 4 4 4 30 Dental Insurance - - - - - 0 0 0 0 0 0 0 2 Health Insurance - - - - - 2 2 2 2 2 2 2 15 Medicare (1.45%) Total - - - - - 0 0 0 0 0 0 0 1 Performance Compensation Total - - - - - 1 1 1 1 1 1 1 9 Savings Plan (4.5%) - - - - - 0 0 0 0 0 0 0 3 Social Security (6.2%) - - - - - 1 1 1 1 1 1 1 4 Hiring Expense - - - - - 10 - - - - - - 10 New Facility Salary & Benefit Total - - - - - 23 13 13 13 13 13 13 103

Travel

AdministrativeEnergy Usage - - - - - 6 6 6 6 6 6 6 42 Generator Fuel - - - - - - - 10 - 0 0 0 11 Hardware - - - - - - - - - 40 - - 40 Hardware - - - - - - - - - 58 - - 58 Hardware - - - - - - - - - 15 - - 15 Property Tax - - - - - - - - - 12 - - 12 New Facility Administrative Total - - - - - 6 6 16 6 131 6 6 178


New FacilityJan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total


Assessments & Fees

Meetings

Communications

Leases & MaintenanceMaintenance -- Hardware -- Servers - - - - - - - - - 226 - - 226 MAINTENANCE - Software:Software - O - - - 41 - - - - - - - - 41 New Facility Lease & Maintenance Total - - - 41 - - - - - 226 - - 267

Outside ServicesAdministration:Human Resources - - - - - - - - - 10 10 10 30 New Facility Outside Services Total - - - - - - - - - 10 10 10 30



Debt Service

EXPENSES - - - 41 - 29 19 29 19 381 30 30 578

SAS70Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total


INCOME - - - - - - - - - - - - -

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2006 TotalSalaries & BenefitsStaff Additions 12 12 12 12 12 12 12 12 12 12 12 12 146 Staff Additions 5 5 5 5 5 5 5 5 5 5 5 5 66 Dental Insurance 0 0 0 0 0 0 0 0 0 0 0 0 4 Health Insurance 3 3 3 3 3 3 3 3 3 3 3 3 40 Medicare (1.45%) Total 0 0 0 0 0 0 0 0 0 0 0 0 3 Performance Compensation Total 3 3 3 3 3 3 3 3 3 3 3 3 32 Savings Plan (4.5%) 1 1 1 1 1 1 1 1 1 1 1 1 10 Social Security (6.2%) 1 1 1 1 1 1 1 1 1 1 1 1 13 Hiring Expense 15 - - - - - - - - - - - 15 SAS70 Salary & Benefit Total 41 26 26 26 26 26 26 26 26 26 26 26 328

Travel

AdministrativeSAS70 Audit - 100 - - 100 - - 100 - - 100 - 400 SAS70 Administrative Total - 100 - - 100 - - 100 - - 100 - 400

Assessments & Fees


SAS70Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total


Meetings

Communications

Leases & MaintenanceMAINTENANCE - Software:Software - - - - - - 41 - - - - - 41 SAS70 Lease & Maintenance Total - - - - - - 41 - - - - - 41

Outside Services



Debt Service

EXPENSES 41 126 26 26 126 26 67 126 26 26 126 26 769

2006 Cash Flow ProjectionsOperating and Capital

OPERATING CASH (000) January February March April May June July August September October November December January 2006

Beginning Cash on Hand 10,500 7,220 8,237 3,459 4,076 4,699 5,226 (564) 1,241 2,433 3,821 5,527 6,565,479$

Assessments 3,447 3,447 3,447 3,447 3,447 3,447 3,447 3,447 3,447 3,447 3,447 3,447 Member Fees 0 1,100 0 0 0 0 0 0 0 0 0 0 NERC Assessment 209 86 0 209 22 0 209 0 0 209 0 0 FERC Fee Assessment 600 600 600 600 600 600 600 600 600 600 600 600 Contract Services Revenue 400 400 450 450 450 952 952 998 998 998 998 1,057 Miscellaneous Income 67 219 58 217 54 211 49 208 47 269 97 256 Operating Income 4,722 5,853 4,555 4,923 4,573 5,210 5,257 5,253 5,092 5,523 5,143 5,360

Salaries & Benefits 2,748 3,191 2,177 2,202 2,290 2,242 2,211 2,184 2,184 2,203 2,147 2,173 Travel 89 90 82 80 64 78 71 61 76 81 60 62 Administrative 1,291 151 82 81 137 92 80 164 46 239 143 65 Assessments & Fees 209 86 0 209 22 0 7,409 0 0 209 0 0 Meetings 70 18 66 27 24 48 39 21 48 40 19 39 Communications 214 217 214 214 215 215 215 215 215 244 244 244 Leases & Maintenance 2,303 223 115 276 287 521 157 88 120 323 86 390 Outside Services 1,059 839 913 1,197 891 869 843 694 716 776 717 729 Regional State Committee 21 21 121 21 21 21 21 21 121 21 21 21 Debt Service 0 0 5,563 0 0 598 0 0 375 0 0 598

Operating Expenses 8,003 4,836 9,333 4,306 3,950 4,683 11,047 3,448 3,900 4,136 3,437 4,321

Cash Surplus/(Deficit) for month

(3,280) 1,017 (4,777) 617 623 526 (5,790) 1,806 1,192 1,387 1,706 1,039

Ending Cash on Hand 7,220 8,237 3,459 4,076 4,699 5,226 (564) 1,241 2,433 3,821 5,527 6,565

CAPITAL CASH (000) January February March April May June July August September October November December

Beginning Cash on Hand 10,400 7,588 7,008 6,518 5,599 5,066 4,557 4,006 3,573 27,088 22,553 21,897 21,926,832$

Capital Expenditures 2,838 599 508 935 547 522 563 443 1,494 4,605 713 26

Interest (26) (19) (18) (17) (14) (13) (12) (10) (9) (69) (57) (56) Additional Borrowings 25,000 Ending Cash on Hand 7,588 7,008 6,518 5,599 5,066 4,557 4,006 3,573 27,088 22,553 21,897 21,927

TOTAL CASH (000) 20,900 14,808 15,245 9,978 9,675 9,766 9,783 3,441 4,814 29,522 26,373 28,492

17

Page 18

2006 Cash Flow

(5,000,000)

-

5,000,000

10,000,000

15,000,000

20,000,000

25,000,000

30,000,000

December2005

January2006

February March April May June July August September October November December

Mon

th E

nd C

ash

on H

and

Operating Cash (000s) Capital Cash (000s)

2006 Capital Expenditures

Corporate IT IT ContractAdministration Affairs Engineering Applications Infrastructure Markets Operations Regulatory RSC Services TOTAL

Capital Expenditure Project (000)Corporate Website Development 0 30 0 0 0 0 0 0 0 0 30 Current Facility Improvements 355 0 0 0 0 0 0 0 0 0 355 Entergy ICT 30 0 0 0 371 0 0 0 0 0 401 Maintenance - Hardware 0 6 41 0 2,351 0 0 0 0 0 2,398 Maintenance - Software 7 0 75 341 656 0 0 0 0 0 1,079 Market Project 0 0 0 0 0 2,043 0 0 0 0 2,043 New Facility 3,585 0 0 0 3,902 0 0 0 0 0 7,487

Total Capital Expenditures 3,977 36 116 341 7,280 2,043 0 0 0 0 13,793

19

Capital Expenditures

Capital Expenditure Item Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec TotalCorporate website redevelopment and design - - - 30 - - - - - - - - 30 Corporate Website Development Total - - - 30 - - - - - - - - 30

Purchase furniture for new hires 75 - - 75 - - 75 - - 75 - - 300 Remodel existing 1st Floor - Sound System 20 - - - - - - - - - - - 20 Remodel existing 6th Floor 35 - - - - - - - - - - - 35 Current Facility Improvements Total 130 - - 75 - - 75 - - 75 - - 355

Purchase furniture for Ict, New Orleans 30 - - - - - - - - - - - 30 Operations -- ICT -- Communications Equip > $1,000 39 - - - - - - - - - - - 39 Operations -- ICT -- Desktop/Laptop PC's 11 - - - - - - - - - - - 11 Operations -- ICT -- Printers > $1,000 9 - - - - - - - - - - - 9 Operations -- ICT -- Servers 75 - - - - - - - - - - - 75 Operations -- ICT -- Software Licenses > $1,000 198 - - - - - - - - - - - 198 Operations -- New Facility-ICT -- Desktop/Laptop PC's - - - - - - - - - 36 - - 36 Operations -- New Facility-ICT -- Printers > $1,000 - - - - - - - - - 3 - - 3 Entergy ICT Total 362 - - - - - - - - 39 - - 401

Record retention - - - - - - - - 3 - - - 3 72" SmartBoard SB580 with Accessories 4 - - - - - - - - - - - 4 MOD Servers - 30 - - - - - - - - - - 30 New MarketSYM Server for Expansion Planning - - 8 - - - - - - - - - 8 Fireproof File Cabinet 3 - - - - - - - - - - - 3 General Office -- Desktop/Laptop PC's 38 - - - - - - - - - - - 38 General Office -- Desktop/Laptop PC's 34 - - - - - - - - - - - 34 General Office -- Desktop/Laptop PC's 14 - - - - - - - - - - - 14 General Office -- Desktop/Laptop PC's 44 - 3 9 3 - - - 3 - - 3 65 General Office -- Desktop/Laptop PC's 22 - - 3 - - - - 3 - - - 28 General Office -- Desktop/Laptop PC's 71 - 6 16 9 11 3 - 6 - 3 - 125 General Office -- Miscellaneous Hardware > $1,000 1 - - - - - - - - - - - 1 General Office -- Printers > $1,000 5 - 13 - - - - - - 3 - - 21 General Office -- Servers 28 - - 10 - - - - - - - - 38 Operations -- AECC -- Desktop/Laptop PC's - - - - - - - - - - - - -Operations -- AECC -- Printers > $1,000 - - - - - - - - - - - - -Operations -- AECC -- Servers - - - 6 - - - - - - - - 6 Operations -- AECC -- Servers - - - - - - - - - 7 - - 7 Operations -- Plaza West -- Desktop/Laptop PC's 32 - - - - - - - - - - - 32 Operations -- Plaza West -- Printers > $1,000 - - 3 - - - - - - - - - 3 Operations -- Plaza West -- Printers > $1,000 - - - - - - - - - - - - -Operations -- Plaza West -- Servers - - - - - - - - - - - - -Operations -- Plaza West -- Servers 174 - - - - - - - - - - - 174 Operations -- Plaza West -- Servers 24 - - - - - - - - - - - 24 Operations -- Plaza West -- Servers 547 - - 8 - - 14 - 21 7 - - 597 General Office -- Communications Equip > $1,000 2 13 4 64 - - 6 - - 723 - - 812 General Office -- Security Equipment > $1,000 100 - - - - 25 - - - - - - 125 General Office -- Security Equipment > $1,000 8 - - - - - - - - - - - 8 General Office -- Servers 8 - - - - - - - - - - - 8 Operations -- AECC -- Communications Equip > $1,000 - - - - - - - - - - - - -Operations -- Plaza West -- Communications Equip > $1,000 120 - - 48 - - - - - - - - 168 Operations -- Plaza West -- Servers 26 - - - - - - - - - - - 26


Capital Expenditures 20

Capital Expenditures

Capital Expenditure Item Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total


Maintenance - Hardware Total 1,303 43 36 164 12 36 23 - 36 740 3 3 2,398

License for One Additional Seat CMS - - 7 - - - - - - - - - 7 IRP Section Tools 75 - - - - - - - - - - - 75 Software:AREVA EMS Change Orders 3 3 3 3 3 3 3 3 3 3 3 3 36 Software:OASIS Change Orders - - - - - 25 - - - - - - 25 Software:OASIS Automation Change Orders - - 20 - - 20 - - 20 - - 20 80 Software:OATI Change Orders - 50 - - 50 - - 50 - - 50 - 200 General Office -- Software Licenses > $1,000 80 - - - - - - - - - - - 80 General Office -- Software Licenses > $1,000 95 - - - - - - - - - - - 95 General Office -- Software Licenses > $1,000 116 26 4 39 5 1 2 - - 1 2 - 196 Operations -- AECC -- Software Licenses > $1,000 - - - - - - - - - - - - -Operations -- Plaza West -- Software Licenses > $1,000 200 - - - - - - - - - - - 200 Operations -- Plaza West -- Software Licenses > $1,000 10 - - - - - - - - - - - 10 General Office -- Software Licenses > $1,000 27 - - 40 - - - - - - - - 67 Operations -- Plaza West -- Software Licenses > $1,000 - - - 8 - - - - - - - - 8 Maintenance - Software Total 607 79 34 89 58 49 5 53 23 4 55 23 1,079

Spot Balancing Market 147 147 147 287 147 147 140 100 140 100 400 - 1,903 Market Monitoring system enhancements - 40 - - 40 - 30 - 30 - - - 140 Market Project Total 147 187 147 287 187 147 170 100 170 100 400 - 2,043

Purchase furniture for new facility - - - - - - - - 25 - - - 25 Purchase furniture for new facility - - - - - - - - 370 - - - 370 Purchase furniture for new facility - - - - - - - - 40 - - - 40 Purchase furniture for new facility - - - - - - - - 20 - - - 20 Purchase furniture for new facility - - - - - - - - 20 - - - 20 Purchase furniture for new facility - - - - - - - - 500 - - - 500 Construction of new facility 290 290 290 290 290 290 290 290 290 - - - 2,610 Operations -- New Facility -- Desktop/Laptop PC's - - - - - - - - - 70 - - 70 Operations -- New Facility -- Desktop/Laptop PC's - - - - - - - - - 24 - - 24 Operations -- New Facility -- Printers > $1,000 - - - - - - - - - 9 - - 9 Operations -- New Facility -- Printers > $1,000 - - - - - - - - - 3 - - 3 Operations -- New Facility -- Servers - - - - - - - - - 98 - - 98 Operations -- New Facility -- Servers - - - - - - - - - 318 - - 318 Operations -- New Facility -- Servers - - - - - - - - - 22 - - 22 Operations -- New Facility -- Servers - - - - - - - - - 1,319 255 - 1,574 Operations -- New Facility -- Software Licenses > $1,000 - - - - - - - - - 610 - - 610 Operations -- New Facility -- Software Licenses > $1,000 - - - - - - - - - 65 - - 65 Operations -- New Facility -- Software Licenses > $1,000 - - - - - - - - - 31 - - 31 Operations -- New Facility -- Software Licenses > $1,000 - - - - - - - - - 219 - - 219 Operations -- New Facility -- Communications Equip > $1,000 - - - - - - - - - 469 - - 469 Operations -- New Facility -- Security Equipment > $1,000 - - - - - - - - - 361 - - 361 Operations -- New Facility -- Servers - - - - - - - - - 8 - - 8 Operations -- New Facility -- Software Licenses > $1,000 - - - - - - - - - 21 - - 21 New Facility Total 290 290 290 290 290 290 290 290 1,265 3,647 255 - 7,487

Grand Total 2,838 599 508 935 547 522 563 443 1,494 4,605 713 26 13,793

Capital Expenditures 21

Southwest Power Pool FINANCE COMMITTEE

Recommendation to the Board of Directors October 25, 2005

Assessment and Tariff Schedule 1 Rate for 2006

Roster Harry Skilton, Chair Director Larry Altenbaumer Director Gary Voigt Arkansas Electric Cooperatives Corp. Trudy Harper Tenaska Doug Henry Westar Energy Michael Desselle American Electric Power Background The Board of Directors establishes the assessment and administrative fee rates utilized by SPP to recover its annual revenue requirement. The Finance Committee monitors the rates established by the Board of Directors and recommends adjustments to the rates as conditions warrant. Analysis SPP’s net revenue requirement as outlined in its 2006 budget is $36MM (adjusted for 2005’s forecasted surplus of $9.7MM). SPP staff estimates 2006 billing determinants of 258,558,000 MWh; indicating a required rate of $0.1392/MWh in order to remain cash neutral during 2006. SPP’s forecast revenue requirement in 2006, prior to adjustment for the 2005 carryover surplus, is $45.7MM or $0.1768/MWh. SPP is scheduled to begin repayment of its 4.78% Senior Notes due 2011 in 2007 which, all other items being equal, will result in an increase in the revenue requirement to $50.7MM or $0.1961/MWh. Should SPP maintain its administrative fee rate at $0.16/MWh during 2006, SPP would expect to carry a surplus of $5.4MM into 2007. Recommendation The Finance Working Group recommends the SPP Board of Directors establish an assessment and tariff schedule 1 rate of $0.16/MWh effective January 1, 2006. Approved Finance Committee October 11, 2005 Action Requested Approve Recommendation

Southwest Power Pool, Inc. HUMAN RESOURCES COMMITTEE


Organizational Roster The following members represent the Human Resources Committee:

Quentin Jackson, Director Harry Dawson, OMPA Richard Spring, KCPL

Phyllis Bernard, Director Mike Palmer, Empire District Trudy Harper, Tenaska

Background SPP staff, at the request of the Human Resources Committee developed the attached Employee Performance Compensation Plan.

Analysis The Human Resources Committee engaged Towers Perrin to perform an evaluation and analysis of SPP’s employee and director compensation programs. The results of Towers Perrin’s work encouraged development of an incentive compensation plan for employees to ensure SPP remains competitive in attracting and retaining qualified personnel.

The Human Resources Committee sought input from the Strategic Planning Committee as well as the Finance Committee to aid in the design of the Employee Performance Compensation Plan. The attached plan represents the finished product which was reviewed by the Human Resources Committee at its October 6, 2005 meeting.

Recommendation The Human Resources Committee recommends approval of the Employee Performance Compensation Plan by the SPP Board of Directors with the plan becoming effective for SPP’s 2005 fiscal year.

Approved: Human Resources Committee 2 votes for, 1 abstention

October 6, 2005

Action Requested: Approve Recommendation

Human Resources Committee Employee Performance Compensation

Southwest Power Pool

Human Resources Committee July 25, 2005

Employee Performance Compensation

Background The Human Resources Committee (HRC) engaged Towers Perrin to provide a report on executive and non-executive compensation practices at electric utilities and ISO/RTOs. Towers Perrin published a report of its findings on August 31, 2004, which was utilized by the HRC to develop a new SPP employee salary structure, ultimately approved by the Board of Directors at its October 27, 2004 meeting. Towers Perrin also recommended adding short-term incentive compensation to SPP’s existing pay practices to match the practices of virtually all companies in its database with which SPP competes for talent and all ISO/RTOs. The HRC asked the Strategic Planning Committee (SPC) to suggest appropriate parameters on which to base this type of compensation. The SPC suggested three parameters for consideration: stakeholder satisfaction, system reliability and cost control. Analysis Staff evaluated many overall compensation plans. Staff is recommending a program focused on equitable pay for outstanding corporate performance rather than achievement of specific individual goals. This plan is meant to maintain the employment culture at SPP, which is highly valued by members and customers. Management believes this will result in continuity of employment and will instill employees with a sense of ownership in the company and its initiatives. This will benefit SPP’s stakeholders considering the complexities of managing volunteer relationships, regulatory and political expectations and public exposure in addition to normal operating issues. Payments under this program will be made in recognition of outstanding corporate and individual performance. Program payments are a part of overall compensation; however they are not to be viewed as an entitlement. The challenge of designing a performance compensation plan is to establish measurable quantitative and qualitative parameters that do not create disincentives to proper performance; i.e. padding budgets, withholding needed maintenance expenditures, or resisting needed organizational direction changes. Successful strategic management depends on accepting the inevitability of change, making some effort to anticipate change, and coping with changes as they occur. Performance Compensation Plan SPP officers utilized this input and an overall program structure recommended by Towers Perrin to develop a performance compensation plan for consideration by the HRC.


Purpose The performance compensation plan is designed to increase the commitment of employees to attaining corporate goals, to promote the management of outcomes, to encourage qualified and trained employees to remain with the company, and to attract new employees by emphasizing operating performance through the opportunity for added compensation beyond the base salary. Plan Management The plan will be administered by the HRC, which shall make annual recommendations to the Board of Directors with respect to annual budgeting, program funding, and plan effectiveness. The decision of the Board of Directors with respect to any questions arising as to awards for the President and interpretation of the provisions of the plan with respect to the office of the President will be final, conclusive, and binding on all parties. The decision of the President with respect to any questions arising as to awards for any employee and interpretation of the provisions of the plan with respect to any employee will be final, conclusive, and binding on all parties. Plan Payment Structure Compensation under the plan will be disbursed annually in the February 28th payroll based on corporate and individual performance for the previous calendar year. Target payouts assigned by salary grade are as follows:

Grade Target % 13 40 12 30 11 20 8-10 15 4-7 10

Target percentages will be applied to actual base salary as of December 31 of the plan year. Incentive compensation will be earned on corporate and individual performance with equal weight being given to three corporate parameters. The aggregate corporate performance will control 100% of the target percentage. The SPP Board of Directors will maintain authority to adjust the SPP President’s target percentage based on individual performance. The SPP President will maintain authority to adjust individual SPP staff member’s target percentage based on individual performance. In no instance will payout under the plan be less than zero. Eligibility All active employees as of December 31 of the Plan Year will be eligible to participate in the plan. Target percentages will be adjusted based on tenure of employment during the year (i.e. an employee beginning employment on July 1 would be eligible for 50% of the target percentage). Employees retiring, passing away or claiming disability status during the Plan Year will be eligible for benefits adjusted based upon the tenure of active employment during the Plan Year should the Company meet its plan targets. Employees terminating their employment with the Company during a plan year, either voluntarily (excluding retirement) or involuntarily, are not eligible for benefits under the Plan.


Cost Control Parameter Adjustments (33% weighting) Annually, the SPP Finance Committee will establish a “foundation budget” including all expected operating expenses not directly identified or affiliated with significant projects or initiatives. Actual aggregate expenses for the fiscal year associated with “foundation budget” items will be divided by the total “foundation budget” to determine the measure. Actual Foundation/Foundation Budget Funding as % of Target >115% -100% 115 %<X>110 0 110 %<X>105 50 105 %<X>95 100 95<X>85 125 < 85 150 Stakeholder Satisfaction Parameter Adjustments (33% weighting) Staff is recommending the use of an online method for measuring customer satisfaction. Retail software is available to create, distribute, and calculate a survey, which can be sent to members, customers, and other stakeholders via email. Software features include: automatically generated reports to assist with real-time results analysis; ability to export survey data to Excel; and the option to keep private or share survey results by providing a specific web link to others. Respondent anonymity can be provided; however, one option allows respondent tracking so a reminder note can be generated to the non-respondents. Overall Survey Results Funding as % of Target Very Dissatisfied (avg <2.5) -100% Somewhat Dissatisfied (2.5<avg<3.0) 0 Satisfied (3.0<avg<3.8) 70 Very Satisfied (3.8<avg<4.5) 100 Extremely Satisfied (avg>4.5) 150 Reliability Parameter Adjustments (34% weighting) Systems Availability, excludes scheduled maintenance (36% weighting) OASIS, RTOSS, ICPP Availability Funding as % of Target All under 99.5% -100% Two under 99.5% 0 One under 99.5% 25 One under 99.8% 75 One under 99.95% 100 All 99.99% or greater 150 Transmission System Reliability (32% weighting for each metric) NERC RC Violations Funding as % of Target


>1 -100% 1 0 0 100

Transmission Assessment Availability Funding as % of Target <99.5% DA and 90% SE -100% 99.5% DA and 90% SE 10 99.8%DA and 95%SE 100 100% DA and 95% SE 150 Corporate Modifier A factor set by the Board of Directors to be applied to the sum of the three parameters above in consideration of corporate conditions not specifically accounted for in the three parameters above. The modifer can range from -20% to plus 20%. Allocation to Individual Participants The above methodology establishes the potential pool of monies to be allocated to individual SPP employees based upon that employee’s contribution to SPPs success in achieving its goals. The SPP Board of Directors will allocate performance compensation payment for the SPP President. The SPP President will allocate performance compensation payments to the SPP staff. Example calculation SPP achieved the following results for fiscal year 200#:

1) actual foundation expenditures equal 105% of target 2) stakeholder satisfaction survey indicated “satisfied” rating of 3.75 3) OASIS availability equals 99.99% 4) RTOSS availability equals 99.4% 5) ICCP availability equals 99.8% 6) Zero NERC RC violations 7) 100% day ahead and 95% state estimator availability

Calculation of SPP plan metrics is as follows:

a) Cost Control: This component has a 33% weighting. From the table the target percentage is 100% therefore:

0.33 x 1.00 = 0.33 b) Stakeholder satisfaction has a 33% weighting. From the table the target

percentage is 70%, therefore: 0.33 x 0.70 = 0.231

c) Reliability parameters have an overall 34% weighting. System availability from the table the target percentage is 25% * .36 = 0.09, NERC RC violations have a 32% weighting. From the table the target percentage is 100%, therefore: 0.32 x 1.00 = 0.32


Transmission Reliability has a 32% weighting. From the table the target percentage is 105%, therefore: 0.32 x 1. 50 = 0.48 Total reliability parameters equals the sum of the individual weighted parameters multiplied by the reliability parameter weighting of 34%as follows: (0.09 + 0.320 + 0.48) * 0.34 = 0.3026

SPP overall performance is obtained by adding together the results from the individual components of the plan: Cost Control 0.333 Customer Satisfaction 0.231 Reliability 0.303 0.867 or 86.7% bonus target The Performance Compensation Target is then presented to the Board of Directors for application of the corporate modifier. In this example, let’s assume SPP missed its budget targets due to implementation of unbudgeted initiatives approved by the stakeholders. The Board felt the Performance Compensation Target was too low and applied a +10% corporate modifier: 0.867 x 1.10 = 0.953 or 95.3% The Performance Compensation Target, together with the funding targets by grade and SPP’s year-end annualized salaries by grade are utilized to compute the available pool of performance compensation funding per the table illustrated below: Funding Adj. Funding Grades Target PCT Target Salaries Pool 13 40% 95.3% 38.1% $300,000 $114,300 12 30% 95.3% 28.6% $970,000 $277,420 11 20% 95.3% 19.1% $964,500 $184,,220 8-10 15% 95.3% 14.3% $6,101,590 $872,527 4-7 10% 95.3% 9.5% $4,325,500 $410,923 Total Pool $12,661,590 $1,809,390 Cost The Performance Compensation pool is expected to average approximately 15% of SPP’s year end annualized salaries. Funding targets for the 2005 plan year will be set at 50% of the targets outlined in this document in recognition of the late year roll-out of the plan.


Recommendation SPP Staff recommends to the HRC approval of the proposed incentive compensation plan for immediate implementation with the first opportunity for payout under the program being February 2006.

Southwest Power Pool, Inc. HUMAN RESOURCES COMMITTEE

Recommendation October 25, 2005

Organizational Roster The following members represent the Southwest Power Pool Human Resources Committee:

Quentin Jackson Phyllis Bernard Harry Dawson Trudy Harper Michael Palmer Richard Spring

Director Director Oklahoma Municipal Power Authority Tenaska Empire District Electric Kansas City Power & Light

Background At the July 25, 2005 Human Resources Committee meeting, the committee requested SPP staff identify steps necessary to rescind the policy of crediting years of service with Member Companies of new SPP employees. Staff was to draft documentation required to effectuate the change in policy.

Analysis The Southwest Power Pool staff requested Mr. Craig Westbrook, outside legal counsel for the SPP Pension and 401(k) Plans to draft amendments to rescind the granting of years of service credit. Additionally, the Southwest Power Pool Vacation Policy would need to be amended to remove the granting of years of service credit verbiage.

Recommendation Terminate SPP’s policy and practice of crediting new employees with years of service with SPP member companies effective November 1, 2005. Employees hired after October 31, 2005 will no longer receive credit for years of service. Adopt amendments to SPP’s retirement plans effective November 1, 2005 defining years of service for employees hired after October 31, 2005 as only that time employed by SPP. Direct SPP staff to amend its vacation policy to define years of service for employees hired after October 31, 2005 as only that time employed by SPP.

Approved: Human Resources Committee October 24, 2005


AMENDMENT TO

SOUTHWEST POWER POOL 401(K) SAVINGS PLAN

The Southwest Power Pool 401(k) Savings Plan is hereby amended, effective ?

2 0 0 , as follows:

Section I(l)(d) is hereby amended, effective November 1, 2005, to read as follows:

I(l)(d) (Select if not counted for all Such Predecessor Employers.) Service with or pay from such Predecessor Employer shall be counted only as to a Predecessor Employer which (Select (i), (ii), or both).

i) [1 maintained a qualified pension or profit sharing plan (or) ii) Only for Employees hired by the Employer prior to November 1, 2005, any

company which is a member of Southwest Power Pool, Inc. at the time such Employee first becomes employed by the Company provided that the Employee was employed by such member immediately prior to becoming an Employee of the company.

IN WITNESS WHEREOF, the Employer has signed this Amendment this day of , 2005.

SOUTHWEST POWER POOL, INC.

Title

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Agenda item 4-3

AMENDMENT TO

SOUTHWEST POWER POOL, INC. RETIREMENT PLAN AND TRUST

The Southwest Power Pool, Inc. Retirement Plan and Trust is hereby amended as follows:

1. Section 2.11 is hereby amended to read as follows, for Employees terminating

employment on or after November 1, 2005:

2.1 1 "EARNINGS" shall mean the amounts paid to an Employee by the Company with respect to services rendered as reported on the Employee's Federal Income Tax Withholding Statement (Forrn W2 or its equivalent) as determined without regard to any rules that limit the remuneration included in wages based on the nature or location of the employment or the services performed, plus the amounts if any, such Employee defers or excludes from wages under a cash or deferred arrangement qualified under Section 401(k) of the Code, under a tax sheltered annuity under Section 403(b) of the Code, or under Section 457 of the Code, Section 125 of the Code or Section 132(f)(4) of the Code.

Notwithstanding the above, Earnings shall not include (1) any lump sum payment of accrued vacation to an Employee terminating employment from the Company or (2) any other lump sum bonus or other payment not part of the Employee's regular salary or a bonus plan generally available to all eligible Employees which is received after or within ninety (90) days before Employee's termination of employment for any reason.

In addition to the foregoing, solely with respect to Participants in the Initial Group, "Earnings" shall mean regular monthly earnings received from Entergy or its affiliates prior to the original Effective Date as determined in accordance with the terms of the Prior Plan.

A Participant who becomes disabled and is entitled to receive benefits from the Company's long term disability plan, shall be considered as remaining employed by the Company for the Period of Service provided in Section 3.1, at the rate of Earnings and for the regularly scheduled number of hours last in effect immediately prior to becoming so eligible.

For Plan Years beginning before January 1,2002, an employee's total Earnings taken into account under the Plan for any Plan Year shall not exceed One Hundred Fifty Thousand Dollars ($150,000) (as adjusted in accordance with Section 401(a)(17) of the Code). For Plan Years beginning afier December 31, 2001, an Employee's total Earnings taken into account under the Plan for any Plan Year shall not exceed Two Hundred Thousand Dollars ($200,000) (as adjusted in accordance with Section 401(a)(17) of the Code).

Earnings means compensation during the Plan Year or such other consecutive twelve (12) month period over which Earnings are otheiwise determined under the Plan (the determination period).

In determining benefit accruals in plan years beginning after December 3 1, 200 1, the annual Earnings limit for determination periods beginning before January 1,2002, shall be ne Hu d ed

Agen8 item 8-J

AMENDMENT TO SOUTHWEST POWER POOL RETIREMENT PLAN AND TRUST

Fifty Thousand Dollars ($150,000) for any determillation period in 1996 or earlier; One Hundred Sixty Thousand Dollars ($160,000) for any determination period beginning in 1997, 1998, or 1999; and One Hundred Seventy Thousand Dollars ($170,000) for any determination period beginning in 2000 or 2001.

2. Section 3.1 is hereby amended, effective November 1, 2005, to read as follows:

3.1 Period of Service

An Employee's Period of Service shall mean the period of the Employee's service with the Company or with an Affiliate commencing on his Employment Commencement Date (or Reemployment Commencement Date) and ending on his Severance Date. Except as otherwise provided in this Article 3, all Periods of Service shall be aggregated.

For Employees hired before November 1,2005, in addition to the foregoing, the Period of Service shall include any Period of Service accrued during service with any company which is a member of Southwest Power Pool, Inc. at the time such Employee first becomes employed by the Company, provided (1) that the Employee was employed by such member immediately prior to becoming an Employee of the Company and (2) such Employee was a participant in a qualified defined benefit pension plan maintained by such member. Such Period of Service shall be recognized as Vesting Service and/or Benefit Service under Plan Sections 3.2 and 3.3; provided, however, that in no event shall any service be counted more than once for the same purpose.

If an Employee quits, is discharged, or retires, and is subsequently reemployed within twelve (12) months of his Severance Date, .the period between his Severance Date and his Reemployment Commencement Date shall be included in his Period of Service; provided, however, if such Employee quits, is discharged or retires during a period of absence from service for other reasons, his Period of Service shall include the period between his Severance Date and his Reemployment Commencement Date only if he is Reemployed within twelve (12) months of his Severance Date.

A Participant's Period of Service shall also include periods during which the Participant is receiving benefits under a Company sponsored long term disability plan until the earlier of: (i) the last day of the month in which such Participant ceases to be eligible to receive payment under such long tern disability program, or (ii) the Participant's Retirement Income Commencement Date.

IN WITNESS WHEREOF, the Employer has signed this Amendment this day of ,2005.

SOUTHWEST POWER POOL, INC.

BY Title

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Page 3, o f ?

Agenda item 4-5

Strategic Planning Committeereport to

Board of Directors/Members Committee

October 25, 2005Inn & Spa at Loretto

Santa Fe, NM

Since the Last Report July 26,2005

• Held one teleconference to discuss:– Non-Disclosure Agreement– Impacts of Energy Policy Act 2005– Organizational Effectiveness Task Force

Since the Last Report July 26,2005

• Held one face to face meeting to discuss:– MOPC Activities– Market Implementation Update– Ancillary Services Market Development– Organizational Effectiveness TF Activities– Contract Services Update– Integrated Resource Planning– Regulatory Update– FERC NOPR/Electric Reliability Organization– Long Term Strategic Planning Process

Organizational Group Assessment Process

• Phase I: Administrative– Directed to Chairman and Staff Secretary

• Reviewed current roster, charter, number of meetings, attendance by members, overall participation, votes taken, costs, accomplishments, pending issues.

• Phase II: Survey– Directed at Members of Specific Group

• Looking for comments on diversity, expertise/skill,meeting materials, preparation, atmosphere, number of meetings, most effective, least effective.

Organizational Group Assessment Process

• Phase III: Review– Directed at all Chairpersons

• Review the results of survey. Make recommendations for changes.

• Phase IV: Presentation:– Directed to MOPC then to Board/Members

Committee.

Recommended Action Item

• Tab 6 – Bylaw Revision for Waiver of Annual Membership Fee

Southwest Power Pool, Inc. STRATEGIC PLANNING COMMITTEE


Bylaws Revision - Waiver of Annual Membership Fee

Background In an order issued October 7, the Federal Energy Regulatory Commission (the Commission) directed SPP to amend its Bylaws to include provisions for certain classes of membership to request a waiver of annual membership fees associated, specifically public interest groups, including large and small retail customer members. Analysis SPP had previously amended its Bylaws to waive withdrawal obligations for these sectors of the membership since that obligation had been raised by some prospective members in these categories as a deterrent to joining SPP. The requirement of payment of an annual membership fee was retained. In its October 7 order, the Commission directed SPP again to develop a process whereby a member in one of the named sectors could request a waiver of the annual membership fee (emphasis added). The Commission also determined that the waiver of withdrawal obligations for some sectors of the membership is “unduly discriminatory” and rejected it. Proposed revisions to the Bylaws are offered for consideration and discussion. Recommendation Approval of Bylaws revisions to be recommended to the Board of Directors for action, following the required notice period to the Membership (30 days).

Approved: Strategic Planning Committee October 13, 2005

Board of Directors

Action Requested: Approval

PROPOSED REVISION SPP Bylaws

October 2005 8.2 Annual Membership Fee

All SPP Members will be subject to an annual membership fee to recover the costs

incurred by SPP related to maintaining reliability criteria and related compliance.

Members without “Net Energy for Load” within SPP will pay an annual membership fee

of $6,000, or other amount established by the Board of Directors. The Board of Directors

shall determine the annual membership fee for the upcoming year in advance of the last

meeting of Members in a calendar year. Those Members serving load will be subject to a

fee based on their annual Net Energy for Load within SPP for the preceding year.

Membership fees are not subject to refund. Members of the Alternative Power/Public

Interest, Large Retail Customer, and Small Retail Customer sectors of the membership

may seek waiver of the annual membership fee. The request for waiver must be directed

to the President in writing 90 days in advance of the start of each fiscal year.

1

SPP Presentation

2

Market and Operations

Policy Committee

Mel Perkins, OG&EChairman

October 25-26, 2005

3

Agenda

Action Item♦ Revisions to Criteria 9

Information Items♦ PRRs recently approved by MOPC♦ Market participant readiness♦ Implications of potential market

delay♦ Formation of MOTRTF♦ Market Tariff filing♦ Expansion Plan

4

Action Item

4

5

Formation of CBSTF

Coordinated Black Start Task Force (CBSTF) formed by ORWG♦ Review and recommend format

and structure changes to the existing black start plan

♦ Recommend changes to SPP Criteria 9 necessary to satisfy requirements of Version 0 NERC Standards

6

Black Start Capability Plan

CBSTF developed a revised draft of the Regional Black Start Plan

Plan was re-titled: “SPP Regional Black Start Capability Plan” (BSCP)

Revised plan satisfies the requirements of the Version 0 NERC Standards

ORWG approved the BSCP

2

7

Regional Restoration Plan

CBSTF developed a new document, “SPP Regional Restoration Procedure”(RRP)

Required by NERC Version 0 Standards

Plan provides a summary of transmission restoration activities by Balancing Authorities and Transmission Operators

ORWG approved the RRP

8

Revisions to Criteria 9

BSCP and RRP incorporated into existing requirements for annual review and updates

Also updated language to be consistent with NERC Functional Model and Version 0 Standards

9

Recommendation

The MOPC recommends the Board of Directors approve the proposed modifications to SPP Criteria 9

(MOPC approved unanimously)

Information Items

10

11

Recent PRRs Approvedby MOPC

Since last meeting, the MOPC has approved 18 PRRs

PRRs deal with remaining issues needed to provide direction to RTWG for development of tariff language to be filed

12

Market Participant Readiness

MOPC covered market readiness in three areas♦ MWG perspective

♦ Independent assessment

♦ Roundtable discussion

3

13

Roundtable Discussion

Each MP reported on♦ System development and testing

♦ Business process development

♦ Staffing and associated training

♦ Development of contractual arrangements

14

Roundtable Discussion

Most MPs are still in progress in one or more of these areas

No MP provided compelling information that a May 1, 2006 implementation can not still be supported

SPP Market Readiness AssessmentOctober 2005

16

Contents

Approach

Summary of Findings

Metrics Framework and Continued Assessment

17

ApproachThe readiness assessment targeted two main deliverables: (1) a current assessment of the state of readiness at SPP and (2) the development of a metrics framework to continually assess the readiness of the SPP markets.

Define Scope and Approach

Gather Information and Conduct

Interviews

Finalize Assessment and Propose Metrics

• Conducted 41 interviews with SPP staff and vendors

• Conducted 10 participant interviews (7 site visits and 3 conference calls)

• Confirmed key areas of focus

• Confirmed review expectations

• Analyzed information and provided insight into issues and risks

• Proposed metrics for continued analysis

18

Approach

Spot Balancing Readiness Assessment

Internal (SPP)• Program Management• Application Readiness• Operations Readiness• Organization Readiness• Migration Readiness• Performance Readiness

Participant Readiness• Management and Tracking• Training• Market Trials• Communications• Program Management• Technical Readiness• Business Readiness

SPPPart.

The assessment assessed risks in both SPP’s internal readiness and SPP’s participant readiness. The participant readiness was further subdivided to view from both the participant’s internal readiness and SPP’s participant facing processes.

4

19

Executive Summary

Low Risk Moderate Risk High Risk

The assessment was broken down into categories with further detail provided at a sub-category level. High level categories are detailed below by the level of risk at which they were assessed.

Application Readiness

Migration / CutoverReadiness

Organization Readiness

Operations Readiness

High Risk Areas• Risk / Issue Mgmt.• Resource Planning• Project Schedule

High Risk Areas• Release Mgmt.

SPP is currently working to address and monitor high risk items identified in this assessment.

Based on our experiences in existing markets, participant readiness becomes of higher risk as the timeline moves towards completion.

Program Management

Participant Readiness

Performance Readiness

20

Highlighted Recommendations

Low Risk Moderate Risk High Risk

The assessment highlighted certain key risk areas. For each of these high risk areas, SPP is currently targeting programs to address. The following highlights recommendations to lower the risk in these areas.

Application Readiness

Migration / CutoverReadiness

Organization Readiness

Operations Readiness

• Perform Bottom up estimates against key areas.

• Centralize issue tracking across vendors / projects

• Hire release manager• Formalize testing around

release processes• Resolve architectural issues

for minimal down time release.

• Publish participant checklist.• Request MOPC / MITF status

on checklist at public meetings.

• Create detailed plan around participant EMS upgrades

Program Management

Participant Readiness

Performance Readiness

• Define operational metrics for key business areas (eg. EMS, MOS)

• Incorporate failover testing scenarios into the schedule.

• Expand SAS 70 backup plan to markets hardware.

21

Metrics Overview

The metrics framework is divided into two pieces: internal and external.

• Internal Metrics– Tied to the critical path phases and milestones– Measures the performance of the program management and delivery.– Allow for early identification of issues and risks

• External Metrics– Used to prove (externally) that the market is ready for operations.– Published on a periodic basis by SPP.– Suggested categories are:

• Program and Project Management• Application Accuracy• Operational Stability• SPP Organizational Readiness• External (Participant) Readiness

The metrics framework is currently being developed and is in review with SPP internal staff. This framework is to provide both for the continued assessment tracking of the program, as well as the metrics to assure of a stable, reliable system at go-live.

22

Metrics and ReportingThe proposed metrics and frameworks are currently in review with a planned acceptance at the next MOPC meeting. The metrics developed are tied to the critical path, and a sample of the metrics are displayed below.

Metric Development Timeline• Metrics are in review

within SPP Staff• MITF review and

approval at November meeting

• MWG approval at December Meeting

• MOPC review at January meeting

• Post MOPC, presented to RSC and Board

9/1 10/1 11/1 12/1 1/1 2/1 3/1 4/1

9/1 10/1 11/1 12/1 1/1 2/1 3/1 4/1

9/1 10/1 11/1 12/1 1/1 2/1 3/1 4/1

9/1 10/1 11/1 12/1 1/1 2/1 3/1 4/1

9/1 10/1 11/1 12/1 1/1 2/1 3/1 4/1

8/22 - 9/30Participant Readiness

ICCP/XML Connectivity(Release 1)

9/30Registration Freeze

for DILB

12/9Backup &Restore

CapabilityConfirmed

1/23 - 2/10DILE Market Trials

(Release 2)

1/13Enable Models

for DILE

1/20 - 2/16Technical TestLow Risk Items

(Release 2)

3/17Last System

Patch DeliveredFor Go-Live

3/13 - 3/24Parallel

Operations(Release 2)

4/21Market Go-Live

Go/No GoDecision

4/20FERC

ApprovesTariff

5/1MarketGo-Live

2/17Enable Production

InfrastructureRequired for

Market Go-Live

12/14Registration

Freezefor DILE

2/20 - 3/3Unscripted

MarketTrials

(Release 2)

1/6Last System

Patch Deliveredfor DILE

4/4Finalize

ConversionPlan with MWG

12/30IT ReleaseProcessesEstablished

3/61) Enable Final Models

For PO, FT andMarket Implementation

2) Go/No-GoDecisionfor PO

4/25MarketOpens

forParticipant

Transactions

11/11Areva Support

MOU Confirmed

11/1 - 12/2DILB Market Trials

NSI / Control Testing(Release 1)

4/3 - 4/14Final Trials(Release 2)

10/21Enable Models

for DILB

1/201) DILE

EnvironmentFrozen

2) BusinessProcessesConfirmedfor DILE

12/14 - 1/17Technical TestHigh Risk Items

(Release 2)

2/24Last System

Patch Deliveredfor PO

9/19 - 11/11Factory Acceptance Testing

(Release 2)

11/14 - 1/13Integration Testing

(Release 2)

3/101) SPP ResourcesHired and Trained

2) Business/ITProcessesConfirmed

for PO

3) Parallel OpsEnvironment

Frozen

4) Finalize ModelingValidations and

PropagationCapability

2/12FinalFERCFiling

3/31Production

EnvironmentFrozen

2/13Registration Freeze

for PO, FT, andMarket Implementation

1/9Go/No-GoDecisionfor DILE

23

EIS Market Implementation

MOPC asked ORWG to evaluate the reliability implications of potential delay in EIS market implementation

ORWG sees no reliability issues with delaying the market implementation

ORWG does have concerns about reliability implications should the market start-up during the summer of 2006

24

EIS Market Implementation

ORWG concerns♦Functionality of new market systems

hardware/software could place additional risk on reliable operations during the summer when system is already stretched

♦Reduction of operating margins resulting from market implementation during the summer increases risk that a system disturbance could be catastrophic

♦Potential for decreased coordination of sales of transmission service could lead to overbooking/underutilization of transmission system

♦Operations personnel need experience with the market prior to the first summer of operation

5

25

MOPC Motion

Given these considerations, the MOPC approved a recommendation from the ORWG that if the EIS Market implementation is delayed beyond the currently scheduled May 1 start date, implementation should not be scheduled during the June 1-September 30, 2006 period.

(MOPC approved unanimously)

26

Formation of the MOTRTF

MOPC formed the Market Operations Tools Readiness Task Force to ensure readiness of tools, systems, and data required for EIS Market implementation

Reports to MOPC

Critical to implementation and ongoing success of market

27

Scope of the MOTRTF

Develop metrics for state estimator, load forecasting and MOS

Identify necessary process improvements to ensure high quality data input

Draft necessary written requirements to be placed on SPP and members

Assess readiness against metrics

28

Market Tariff Filing

Filing to address necessary tariff changes to support modifications to market design and protocols

Includes reliability solutions

Will address deficiencies identified by FERC in recent order

MOPC to meet November 30 to review and approve tariff changes

29

SPP Expansion Plan

TWG presented the expansion plan to MOPC for approvalDue to various concerns, MOPC withheld approvalHope to have concerns addressed at upcoming CAWG workshop scheduled for November 10

Questions

30

Southwest Power Pool, Inc. MARKETS AND OPERATIONS POLICY COMMITTEE

Recommendation to the Board of Directors/Members Committee October 25, 2005

Organizational Roster The following members represent the Operating Reliability Working Group:

Gerry Burrows, KCP&L Bob Cochran, SPS Allen Klassen, Westar Pete Kuebeck, OG&E Steve Massey, Westar

Scott Moore, AEP (Chair) Maxwell Reid, CLECO Keith Sugg, AECC Jim Thompson, Constellation Energy Noman Williams, SECI

The following stakeholders participated in group discussions:

Dan Boezio, AEP Bob Cochran, SPS Mike Crouch, WFEC Will Franklin, Entergy Mike Gammon, KCP&L Steve Hillman, WPEK Allen Klassen, Westar Pete Kuebeck, OG&E

John Mason, MPS Stan Mason, SPA Steve Massey, Westar Jim McAvoy, OG&E Scott Moore, AEP Bill Nolte, SECI Bary Warren, EDE Noman Williams, SECI

Background The Operating Reliability Working Group (ORWG) charged the Coordinated Black Start Task Force (CBSTF) with several tasks on March 25, 2004. One of these tasks was to recommend changes to the SPP Criteria with regards to the following:

a) Formalized coordination between neighboring entities

b) Guidelines and/or criteria regarding verification of black start capability

c) Guidelines and/or criteria for modification of black start plans

Analysis The CBSTF reviewed Criteria 9 in light of NERC Version 0 Standards and the ORWG’s charge. Through this process, the CBSTF made the necessary modifications to Criteria 9 and presented those changes to the ORWG at its September 2005 meeting. The ORWG reviewed the proposed language for Criteria 9, made slight modifications to that language and approved the Criteria 9 changes as modified.

Recommendation

The MOPC recommends the Board of Directors approve the proposed revisions to SPP Criteria 9.

Approved: Operating Reliability Working Group September 7, 2005 Passed Unopposed

Markets and Operations Policy Committee October 12, 2005

Passed Unopposed


Southwest Power Pool Criteria

9-1 May 7, 2002

9.0 BLACK START This document provides general guidelines to be followed in the event of a partial or

complete collapse of the SPP bulk electric system. Quick implementation of each

Balancing Authority/Transmission Operator restoration plan compiled according to this

Criteria and the NERC Reliability Standards shall facilitate coordination between

member Balancing Authorities/Transmission Operators and the SPP Reliability

Coordinator and insure the earliest possible restoration of the electric system. It is

impossible to predict all the possible combinations of system problems that may occur

after a major electric system failure. It is therefore the responsibility of system operators

to restore the electric system applying the general guidelines outlined in this document

and in their respective detailed black start plans. Strict adherence to other SPP Criteria

is also necessary for a prompt restoration of the electric system. Mutual assistance

between members Balancing Authorities/Transmission Operators is highly encouraged.

This assistance may include the sharing of black start units. The SPP Reliability

Coordinator shall take an active role during electric system restoration as outlined in this

Criteria. Each Balancing Authority/Transmission Operator shall have a readily accessible

and sufficiently detailed, current restoration plan to assist in an orderly restoration.

Restoration shall be aided by communicating to neighboring Balancing

Authorities/Transmission Operators and the SPP Reliability Coordinator an accurate

assessment of the network conditions throughout the restoration process.

Communication shall be established between neighboring operation centers, power

plants and the SPP. Mutual assistance and cooperation are essential during restoration

activities to avoid reoccurrence of a partial or complete electric system collapse.

9.1 Responsibilities

SPP shall develop and maintain a Regional Black Start Capability Plan and a Regional

Restoration Plan in accordance with NERC Reliability Standards. The Regional Black

Start Capability Plan and Regional Restoration Plan will be reviewed on an annual basis

to ensure the plans maintain effectiveness and accuracy. It is the responsibility of SPP

Staff to review and update the plans as required and to bring such proposed updates to

the Operating Reliability Working Group (ORWG) for their review and approval. The

annual review and any proposed updates are to be submitted to the ORWG no later than

April 1.

Deleted: For more detailed information please refer to the SPP regional black start plan.

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9-2 May 7, 2002

9.1.1 Members Each Balancing Authority/Transmission Operator shall develop and maintain a detailed

internal black start plan. Each Balancing Authority/Transmission Operator shall review

their black start plan annually and shall provide SPP with the latest version of their black

start plan whenever changes are made or as requested by SPP Staff. Transmission

Operators shall prepare a plan in cooperation with their responsible Balancing Authority

designed to assist and coordinate with the Balancing Authority’s plan. This applies to

cogeneration facilities and independent power producers. A copy of this plan shall be on

file at the SPP office. Black start plans shall be verified by a minimum of simulation

testing, although actual physical testing is highly encouraged where feasible. Members

shall report any testing activities of black start plans to the ORWG.

Balancing Authorities and Transmission Operators shall train appropriate personnel in

the implementation and execution of their black start plan.

In the event of an electric system collapse, each Balancing Authority/Transmission

Operator shall use the following items as guiding principles for the restoration process.

a. Provide assistance to any and all SPP Balancing Authorities and

Transmission Operators as abilities allow, with priority given to the

restoration of inter-system bulk electric system ties

b. Make adjustments to interchange schedules between affected areas as

necessary to facilitate restoration efforts

c. Take immediate steps to initiate internal restoration plans

d. Supply neighboring Balancing Authorities/Transmission Operators and the

SPP Reliability Coordinator with information on network status

e. Coordinate with neighbors the re-connection of Balancing Areas and/or

islands.

f. If it becomes apparent that the emergency is of regional magnitude, the

focus of restoration action shall shift from individual Balancing Area

priorities to bulk network priorities. Priority to a neighboring Balancing

Authority/Transmission Operator load may be necessary in order to benefit

the overall strength of the bulk electric system. As generation and

Formatted: Bullets and Numbering

Deleted: member Control Area

Deleted: and train associated personnel (system operators, power plant operators, etc.) in its implementation.


Deleted: at least

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Deleted: the member Control Area black start plan

Deleted: Non-Control Area members



Deleted: Operating Subcommittee

Deleted: Control Area members

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9-3 May 7, 2002

transmission facilities become available, systematic restoration of network

load shall be initiated with respect to priorities

g. Generation should be made available to all regional utilities for system and

customer load restoration as recommended by the SPP Reliability

Coordinator

9.1.2 SPP Reliability Coordinator The SPP Reliability Coordinator shall be familiar with each Balancing

Authority/Transmission Operator black start plan that is on file. In the event of a failure

of the bulk electric system, the SPP Reliability Coordinator personnel shall take the

following action.

a. The SPP Reliability Coordinator has the authority to temporarily suspend

normal energy scheduling practices and to restore those practices once an

operating emergency has been mitigated.

b. The SPP Reliability Coordinator should recommend sharing of generation

available to all regional utilities for system and customer load restoration.

c. Maintain continuous surveillance of the status of the networks of all member

Balancing Authorities (refer to section 9.4 for information required).

d. Act as a central information collection and dissemination point for Balancing

Authorities/Transmission Operators.

e. Communicate with other regional offices, NERC and the Federal Emergency

Management Administration.

f. Communicate/recommend the need for assistance to appropriate Balancing

Authorities/Transmission Operators.

g. The SPP Reliability Coordinator shall approve, communicate, and

coordinate the re-synchronizing of major system islands or synchronizing

points..

h. The SPP Reliability Coordinator shall expect notification of Balancing

Authority status. It is necessary that this information be recorded and

shared with all Balancing Authorities/Transmission Operators. Based on this

information, the SPP Reliability Coordinator shall immediately assess

electric system conditions and status of communication facilities and inform

Deleted: .

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Deleted:


Deleted: members

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Deleted: The SPP Reliability Authority shall assist Control Areas in a coordinated restoration by monitoring implementation of plans, by providing status information to appropriate Control Areas, and by facilitating assistance and re-connection


Deleted:


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Deleted:



9-4 May 7, 2002

all Balancing Authorities of the extent of the blackout (refer to section 9.4 for

information required).

9.2 Elements of Balancing Authority/Transmission Operator Black Start Plans Each Balancing Authority/Transmission Operator shall maintain a black start plan that is

consistent with the NERC Reliability Standards. All plans and procedures shall be

readily available to system operators, plant operators and the SPP Office. System

operators shall review these documents on a regular basis. It is suggested that

Balancing Authority/Transmission Operator black start plans include the following

elements.

a. Philosophies and strategies for Balancing Area restart

b. Identification of the relationships and responsibilities of the personnel

necessary to the restoration

c. Identification of black start resources including generating unit resources,

sufficient fuel resources, transmission corridors or paths, communication

resources and power supplies, mutual assistance arrangements

d. Contingency plans for failed resources

e. Identification of critical load requirements

f. Identification of special equipment requirements

g. Provisions for training and documentation of training for personnel

h. Provisions for simulating and where practical, actual testing and

verification of the resources and procedures

i. General instructions and guidelines for system operators, plant operators,

communications personnel, and transmission and distribution personnel

j. Provisions for public information

k. Synchronization Guidelines including operating instructions and

procedures for synchronizing areas as may be dictated in the restoration

plan

l. The functions to be coordinated with neighboring Reliability Coordinators,

Balancing Authorities, and Transmission Operators

Formatted: Bullets and Numbering


Deleted: .

Deleted: Member

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Deleted: this Criteria.

Deleted: member

Deleted: Control

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9-5 May 7, 2002

m. Notifications to neighboring Reliability Coordinators, Balancing

Authorities, Transmission Operators, and other operating entities as

phases of the restoration plan are implemented

Appendix 4 contains a list of items to be considered in the restoration process that may

be used in the development or review of black start plans. 9.3 Restoration Priorities

The following actions for system restoration shall be considered by each Balancing

Authority and assigned proper sequence and priority.

a. Stabilization of generating units

b. Restoration of inter-system and intra-system bulk electric system ties

c. Restoration and maintenance of intra- and inter-system communication

facilities and networks

d. Assessment of Balancing Area condition and SPP electric system

condition

e. Contact with public information agencies (Emergency Broadcasting

System) to request the broadcasting of pre-distributed appeals and

instructions

f. Restoration of units with black start capability

g. Providing service to critical electric system facilities

h. Connection of islands taking care to avoid reoccurrence of a partial or

complete system collapse and equipment damage

i. Restoration of service to critical customer loads

j. Restore service to the remaining customers

9.4 Information Communication

Reliable communication between Balancing Authorities/Transmission Operators and

SPP Reliability Coordinator will be the key to a safe and timely restoration following a

collapse of the SPP network. As part of the initial assessment after a partial or complete

system blackout, communication facilities shall be tested and verified. System operators

shall establish communication within their area with special emphasis given to power

plants and neighboring members. To expedite the recovery process, the SPP

Emergency Communication Network (satellite phones) shall be used to convey

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9-6 May 7, 2002

appropriate information to members. Balancing Authorities/Transmission Operators shall be prepared to communicate their status once an hour, or when polled by the SPP Reliability Coordinator Only after voice communication paths have been

established shall efforts be directed to re-establishing data communication paths.

System status conditions to be surveyed include but are not limited to the following

items.

a. Areas of the electric system that are de-energized

b. Areas of the electric system that are functioning

c. Amount of generation and generating reserve available in functioning

areas

d. Power plant availability and time required to restart

e. Status of transmission breakers and sectionalizing equipment along

critical transmission corridors, and at power plants

f. Status of transmission breakers and sectionalizing equipment at tie points

to other areas

g. Status of fuel supply from external suppliers

h. Under-frequency relay operation

i. Relay flags associated with circuits tripped by protective relays

j. Status of communication systems


Deleted: are to


Deleted: or whenever any significant change occurs.

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Summary 10/17/2005

Market ParticipantReadiness / Connectivity

Testing Status

Readiness / Connectivity

Testing Notes

Participant Registration

Status

Participant Registration

Notes

Participant Training Status

Participant Training

Notes

AEP G Completed all testing GConfirmation needed from AEP regarding the Market Registration of 1 Unit modeled in EMS See Detailed Status See Detailed Status

Ok. Gas and Electric Co. G Completed all testing G See Detailed Status See Detailed Status

SW Public Service Co. (XCEL) G Completed all testing G

Confirmation needed from SPS for EMS Modeling of6 units that were requested for Market Registration.

Confirmation needed from SPS regarding Market Registration of 3 Units modeled in EMS. Units are owned by Golden Spread but may be represented in market by SPS. See Detailed Status See Detailed Status

Westar Energy, Inc. G Completed all testing Y

Confirmation needed from SPP and Westar regarding Westar request to model 4 units as Behind the Meter See Detailed Status See Detailed Status

Kansas City Power and Light Co. YScheduled for make-up testing. Y

Confirmation needed from KCPL for EMS Modeling related to 1 Unit See Detailed Status See Detailed Status

Aquila (WPEK/MPS) R

Unknown as to MPS assets. Did not schedule any testing as of 9/30. Y

Confirmation needed from Aquila regarding the Assets that will be Registered for the Market for the MPS Control Area. See Detailed Status See Detailed Status

Coral Power RDid not schedule any testing as of 9/30. R

Need to confirm Market Registration Status based on Coral Power's ERCOT Market Participation See Detailed Status See Detailed Status

Redbud Energy LP YScheduled for make-up testing. G See Detailed Status See Detailed Status

Empire District Electric Company G Completed all testing YConfirmation needed from EDE for EMS Modeling related to 2 Units See Detailed Status See Detailed Status

Grand River Dam Authority RDid not schedule any testing as of 9/30. G See Detailed Status See Detailed Status

Calpine Energy Service LP G Completed all testing G See Detailed Status See Detailed Status

Western Farmers Electric Coop (WFEC) G Completed all testing YConfirmation needed from EMS Engineering regarding EMS Modeling of WFEC SPA Load See Detailed Status See Detailed Status

Exelon Gen. Company LLC YDid not finish testing as of 9/30. G See Detailed Status See Detailed Status

Entergy Power Ventures YScheduled for make-up testing. G See Detailed Status See Detailed Status

The Energy Authority G Completed all testing GConfirmation needed from TEA regarding Market Registration of 1 Unit that is not modeled in EMS. See Detailed Status See Detailed Status

City of Indep. - Power and Light Dept YDid not finish testing as of 9/30. G See Detailed Status See Detailed Status

Eastman (Tenaska) YDid not finish testing as of 9/30. G See Detailed Status See Detailed Status

ONEOK Energy Mktg and Trading Co., L.P. RDid not schedule any testing as of 9/30. G See Detailed Status See Detailed Status

Arkansas Electric Coop Corp YScheduled for make-up testing. G See Detailed Status See Detailed Status

Midwest Energy RDid not schedule any testing as of 9/30. Y

Need SPP and Westar to confirm Behind the Meter Request for MIDW's Asset See Detailed Status See Detailed Status

Ok. Municipal Power Authority RDid not schedule any testing as of 9/30. G See Detailed Status See Detailed Status

© 2005 SPP and Accenture LLP. Confidential and Proprietary. All Rights Reserved.

MT Scorecard 10/17/2005

Market ParticipantParticipant ReadinessTesting1

ICCP Connectivity

Testing (CAs) 1

XML Message Connectivity

Testing1

Status

AEP C C C All required testing completed

Ok. Gas and Electric Co. C C CPCI is assisting OGE. ICCP testing to be scheduled with John Heir the week of 9/26/05. One open XML message connectivity test item that is listed as an issue.

SW Public Service Co.(XCEL) C C C All required testing completedWestar Energy, Inc. C C C All required testing completed

Empire District Electric Company C C C

Completed some PRT interaction methods, no further testing scheduled for PRT (using API as production method) or for XML Message Connectivity Testing as they are still choosing a vendor. GW to follow-up to find out timeline for vendor selection/implementation.

Calpine Energy Service LP C C All required testing completedWestern Farmers Electric Coop (WFEC) C C C PRT and ICCP and XML Message Connectivity testing scheduled for 9/27/05. The Energy Authority C C C All required testing completed

Kansas City Power and Light Co. S C S

10/10/05 - Scheduled for PRT and XML Listener Testing on 10/29/05.9/29/05 - Per Patricia Denny, KCPL has committed to having their API functionality ready to be tested by the second week of November. XML listener testing has been attempted.

Redbud Energy LP S S

10/10/05 - Scheduled for PRT and XML Listener Testing on 10/31/05.Only one resource registered. SP has been notified that Redbud will be utilizing a third party consulting company to assist. SP to follow-up with Redbud to assertain timeline for implementation.

Exelon Gen. Company LLC DNF NS

Carl Monroe contacted MOPC member from Exelon over the past two weeks. Conference call was held by DM (Carl Monroe attended) and Julie Palin from Exelon on 9/7/05. DM has facilitated technical conversations between Spencer Stillwell of Exelon and Cody Parker from SPP. 9/26/05 - DM received a message from Eric Olsen from Exelon indicating that they plan on testing prior to 9/30/05. DM to confirm date and time of testing.

Entergy Power Ventures(as ENKO) DNF S

10/10/05 - Scheduled for XML Listener Testing on 10/29/05.9/30/05 - Per James Fife, EPV commits to be ready to test XML Listener functionality by 10/15/05.

City of Indep. - Power and Light Dept C NS NS9/29/05 - Per Paul Mahlberg, City of Indep is focusing on an upcoming NERC readiness audit and cannot commit to testing until 11/30/05

Tenaska (as Eastman) DNF NS

There was confusion as to who was going to submit data for Eastman. After a few discussions, it appears that Tenaska will be acting as the DA for Eastman. Pending registration updates are preventing Tenaska from completing Participant Readiness Testing. Jim Bartoldus is working with Mike Crosby and Areva to repair the Tenaska/Eastman registration relationships.

Arkansas Electric Coop Corp C S

10/10/05 - Scheduled for XML Listener Testing on 10/31/05.9/30/05 - Per Mike Hood, AECC commits to be ready to test XML Listener functionality by 10/31/05

Midwest Energy NS NS and not included in the Market. SPP staff is evaluating the request. If the resources are


MT Scorecard 10/17/2005

Market ParticipantParticipant ReadinessTesting1

ICCP Connectivity

Testing (CAs) 1

XML Message Connectivity

Testing1

Status

Aquila (WPEK/MPS) NS NS NS

Only WPEK resources are registered (5 small resources). SP working with Aquila to assertain status of implementation. Recent press release indicated that the WPEK resources are being sold to the same Co-op that owns Sunflower.9/26/05 - SP to complete registration package for MPS resources for Aquila and treat as an unexecuted agreement. The Aquila package will be referred to Pat Bourne for further action.9/29/05 - Per Mitch Krysa, Aquila has committed to being able to complete Participant Readiness testing by 10/20/05, ICCP testing by 11/10/05, and XML Message Connectivity Testing completed by 11/30/05. This still only pertains to the WPEK resources.

Coral Power NS NS

Conference call held between Coral and SPP (with Carl Monroe) to discuss next steps. Initially, Coral thought they would have to install an ICCP circuit, so no action was taken at the time to prepare for market entry. 9/26/05 - Rick Broussard indicated on 9/26/05 that Coral only has essential staff available and may not be able to support testing by end of week. Coral will only be submitting data manually through the Portal at this time and has not indicated their intended method for production. DM following-up with Rick Broussard to determine schedule for PRT and/or XML message connectivity testing.

Grand River Dam Authority NS NS NS

9/30/05 - Per Mike Stafford, GRDA commits to being ready for ICCP and XML Message Connectivity Testing by mid November, and Participant Readiness Testing during the November/December timeframe.

ONEOK Energy Mktg and Trading Co., L.P. NS NS

ONEOK intends on selling their market assets prior to market opening to an undisclosed party and has halted testing until the decision on the sale is finalized.9/26/05 - The ONEOK package will be referred to Pat Bourne for further action.

Ok. Municipal Power Authority DNF NS

Carl Monroe contacted OMPA to assertain Market Status. Response was that they have no XML listener functionality developed and do not have further submission testing scheduled. DM to follow-up with Todd Ossenkopp to determine timeline for development (and scheduling of meeting with Aaron Ralls if necessary).

Note 1:C - CompleteNS - Not ScheduledS - ScheduledIP - In ProgressDNF - Did Not Finish/No Further Testing Planned


Training Spr. 05 Scorecard 10/17/2005

Market Participant

Mkts 201Interchange Scheduling

NLS: Bus. Functions

NLS: Prog. Interface Gap for Rel./Ops Gap for IT

NLS: User Interface Resource Plans AS Plans

Offer Submission Gen. Control Settlements RSS Mkt. Monitoring

AEPAquila (WPEK/MPS)Arkansas Electric Coop CorpCalpine Energy Service LPCity of Indep. - Power and Light DeptCoral PowerEastman (Tenaska)Empire District Electric CompanyEntergy Power VenturesExelon Gen. Company LLCGrand River Dam AuthorityKansas City Power and Light Co.Midwest EnergyOk. Gas and Electric Co.Ok. Municipal Power AuthorityONEOK Energy Mktg and Trading Co., L.P.Redbud Energy LPSW Public Service Co. (XCEL)The Energy AuthorityWestar Energy, Inc.Western Farmers Electric Coop (WFEC)

Vendor/OtherEntegra Power GroupAmeren EnergyACES PowerNew Energy AssociatesPCIOATIPSIConstellation CommoditiesBoston Pacific

TOTAL 22 16 13 32 7 5

Indicates at least one person frommarket participant company has

attended the training.

Indicates that no one from the MP company has attended the training.

Fall 2005 Training Courses


Training Fall 05 Scorecard 10/17/2005

Market Participant

Mkts for IT (2/8/05) Mkts. for IT (2/15/05) XML Specifications Markets 201 Resource Plans A/S Plans Offer Submission Generation Control SettlementsAEPAquila (WPEK/MPS)Arkansas Electric Coop CorpCalpine Energy Service LPCity of Indep. - Power and Light DeptCoral PowerEastman (Tenaska)ETEC/Tex-La GDS GDSEmpire District Electric CompanyEntergy Power VenturesExelon Gen. Company LLCGrand River Dam AuthorityKansas City Power and Light Co.Midwest EnergyOk. Gas and Electric Co.Ok. Municipal Power AuthorityONEOK Energy Mktg and Trading Co., L.P.Redbud Energy LPSW Public Service Co. (XCEL)The Energy Authority KCBPUWestar Energy, Inc.Western Farmers Electric Coop (WFEC)

Vendor/OtherEntegra Power GroupAECIAmeren EnergyACES PowerNew Energy AssociatesPCIOATIPSIConstellation CommoditiesBoston PacificGlobal EnergyThe Structure GroupCeleritasInteg ConsultingSPARainbowSunflowerGPESGolden SpreadCity Utilities - Springfield

TOTAL 38 28 45 89 67 67 67 67 34

Indicates at least one person frommarket participant company has attended the

training.

Indicates that no one from the marketparticipant company has attended the

training.

Spring 2005 Training


Registration Scorecard 10/17/2005

Registration Discrepancy Report as of 10/14/05

Count of Status StatusTCNAME Need Participant confirmationAMERICAN ELECTRIC POWER 1ENERGY AUTHORITY, THE 1GOLDEN SPREAD ELECTRIC COOPERATIVE INC. 3KANSAS CITY POWER AND LIGHT, CO 1SOUTHWESTERN PUBLIC SERVICE COMPANY 7WESTAR ENERGY, INC. 5WESTERN FARMERS ELECTRIC COOPERATIVE 1EMPIRE DISTRICT 2Grand Total 21


Documents

Southwest Power Pool BOARD OF DIRECTORS/MEMBERS … · Mr. Jackson reported that SPP requested Mr. Craig Westbrook, outside legal counsel for the SPP Pension and 401(k) Plans, draft