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Southwest Power Pool

BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING

The Skirvin Hilton Hotel

April 24, 2007

- Summary of Action Items - 1. Approved minutes of the January 30, 2007 Board of Directors/Members Committee meetings. 2. Approved SPP’s execution of the RE Delegation Agreement with FERC within 30 days and work with the

Strategic Planning Committee to bring the agreement into compliance within 180 days. 3. Approved the Markets and Operations Policy Committee’s recommendation of proposed tariff language for

changes to Sections 18.4 and 32.4 regarding a Letter of Credit. 4. Approved the Markets and Operations Policy Committee’s recommendation of proposed tariff language for

changes to Section 28.4 limiting the amount of secondary network service. 5. Approved the Markets and Operations Policy Committee’s recommendation to approve SPP Staff

recommendation to provide waivers of such extent that projects required for the AECC and OMPA new designated resources are fully Base Plan funded.

6. Approved the Markets and Operations Policy Committee’s recommendation of proposed tariff language for

changes to implement PRR 124, 140, and 143. 7. Approved the Human Resources Committee’s recommendation to establish a Roth option as part of the SPP

401(k) plan. 8. Approved the Finance Committee’s recommendation to accept the 2006 SPP Audit Report. 9. Approved the Finance Committee’s recommendation that the SPP Board of Directors borrow $30 million from

US Bank and borrow $20 million from JP Morgan Chase on the terms indicated in each bank’s term sheets. The SPP Board of Directors should authorize the SPP President and CFO to jointly execute all evidence of the above indebtedness.

10. Approved the Finance Committee’s recommendation to direct SPP staff to submit a filing to the Arkansas

Public Service Commission requesting authority to issue $30 million in term financing and $20 million in revolving notes.

11. Approved the Finance Committee’s amended recommendation to determine cost benefit and make necessary

changes to protocols to allow issuance of initial settlement statements. Initial settlement statements should be provided to the Finance Committee in advance of the September 19, 2007 meeting.

MINUTES NO 111

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The Skirvin Hilton Hotel

April 24, 2007 Agenda Item 1 - Administrative Items SPP Chair Mr. Jim Eckelberger called the meeting to order at 8:35 a.m. The following Board of Directors/Members Committee members were in attendance, via teleconference, or represented by proxy:

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

Mr. Eckelberger asked for a round of introductions. There were 62 persons in attendance either in person or via phone representing 23 members (Attendance List - Attachment 1). Mr. Brown reported proxies and a quorum was declared (Proxies - Attachment 2). Mr. Eckelberger referred to draft minutes of the January 30, 2007 meeting. Mr. Eckelberger then asked for corrections or a motion for approval (1/30/07 Meeting Minutes - Attachment 3). Mr. Martin moved that the minutes be approved as presented. Mr. Jackson seconded the motion, which passed. Agenda Item 2 – Review of Past Action Items Ms. Stacy Duckett presented a list of past action items.

• The Corporate Governance Committee was to start the nominating process for Members Committee terms expiring at the end of 2007.

Status: Mr. Brown will provide an update during the Corporate Governance Committee report.

• A request for revision to charts on Pages 33-34 of the Presidents Quarterly Report. Status: Data is being assembled and expect to include for July meeting.

• Proposal for revisions to expedite the Aggregate Study process. Status: pending

SPP Board of Directors/Members Committee Minutes April 24, 2007

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• Request for interim status reports on SAS70 audit. Status: Mr. Skilton will address in Finance Committee report.

• MOPC to determine a uniform definition and calculation for Net Energy Status: pending

Agenda Item 3 – President’s Report Mr. Nick Brown provided the SPP President’s report (2007 1Qtr Report – Attachment 4). The Board of Directors will meet for an educational meeting on June 11 and 12 in Little Rock. The meeting will include a tour of the new operation center followed by reports from Members to present company information and what their company expects from SPP. Mr. Carl Huslig (ITC Great Plains) and Mr. David Brian (East Texas Cooperatives) have been asked to speak on be half of their companies. Other topics on the agenda will include: metrics for organizational performance, Balancing Authorities, future Market items, and the Regional Entity transition. The Second Annual SPP Leadership Conference is scheduled for May 7. Professor David Garvin of Harvard will be the guest speaker. This is primarily for the SPP staff although others are invited to attend. SPP staff currently numbers 257 with 21 new hires and 31 positions to fill by the end of 2007. Mr. Bill Wylie (formerly of OG&E) has joined the SPP staff as the Director of the Center of Excellence. SPP is currently party to 99 dockets on the state and federal level. SPP has added two new members: Mid-Kansas Electric Cooperative as of April 1and Trans-Elect Development Company as of May 1. The new operation center opened this month in Maumelle, AR. The transition was a non-event and will continue through the end of the year. FERC issued an order on NERC’s delegation agreements with Regional Entities (RE). SPP’s filing was approved with some modifications required to ensure independence of the RE Trustees from the Board of Directors. The order requires that a delegation agreement be executed within 30 days and a compliance filing in 180 days. Mr. Brown suggested executing the delegation agreement as soon as possible and taking the 180 days to fully comply. This would require 2 action items: modifying the SPP Bylaws and electing the RE Trustees. This will require a special Board of Directors meeting and a special Meeting of Members in mid June. Mr. Brown moved to execute the delegation agreement with FERC and to work with the Strategic Planning Committee to bring the agreement into compliance. Mr. Skilton seconded the motion. The Members were in unanimous favor. The motion passed. Mr. Brown provided a report regarding demanded response (Demand Response Presentation – Attachment 5). FERC ordered SPP on September 26, 2006 to “coordinate with utilities, state commissioners and other interested parties to consider provision for participation of demand resources in the imbalance market.” March 20, SPP filed for an extension and is now required to file by September 26, 2007 either modifications to the tariff or an explanation for not including such modifications. Mr. Brown reviewed challenges ahead including: a carbon constrained environment, peak demand and capacity margins, reserve margins, CO2 and green house gas emissions, and coal. He asked if we are going to simply check off the task ahead or take meaningful action. Mr. Eckelberger announced that this would be the last meeting for Commissioner Denise Bode (OK) and possibly the last for Commissioner Brian Moline (KS) and Commissioner Steve Gaw (MO). He asked the commissioners for any parting comments. Commissioner Moline expressed appreciation in working with the RSC and the SPP Board. He advised: build transmission lines, sooner than later; be aware of cost of SPP and costs related to it; and don’t get distracted, build before demand response. Commissioner Bode expressed appreciation for the opportunity to work with RSC and the SPP Board. She stated that this was a time of great opportunity with the new issues today and urged that it is critically important to plan for strategic issues.


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Agenda Item 4 – Regional State Committee Report President Julie Parsley presented the Regional State Committee (RSC) report. The RSC agenda included reports, updates and discussion on the following items:

• Mr. Carl Monroe presented numbers quantifying utility costs and facilities of Wind Integration. Currently there are approximately 1200 – 1500 MW operational and 112,000 MW in the queue with a potential of 40,000 MW. There is an additional cost of $2 – $5 or $6 per MW hour for utility operations.

• RSC will provide a formal vote to provide input regarding waivers for Base Plan Funding until the process matures and it is no longer necessary. The RSC realizes that this is not a binding vote.

• FERC approved a region wide/ postage stamp pricing for new PJM facilities operating at 500 MW and above. RSC is pleased that FERC is willing to look at regional differences.

• President Parsley recognized the significance of SPP receiving FERC approval for the NERC Regional Entity Delegation Agreement and offered congratulations.

• The Cost Allocation Working Group (CAWG) is designing a balanced portfolio of economic projects for the SPP footprint. Stakeholders’ comments were solicited. Comments were few and CAWG would like more participation moving forward. Mr. Eckelberger encouraged stakeholder input on economic upgrades.

• RSC Bylaws and Travel Policy were revised: o Electronic voting will be allowed for non-policy and administrative matters. o SPP will continue to act as agent for payment of routine meeting and travel expenses.

RSC Board of Directors will provide approval to the appropriate person within SPP for payment of non-routine expenses and those of a more financially significant nature.

o RSC will reimburse RSC members and/or their delegated representatives for travel expenses.

o Submittal of travel expenses was extended from 30 to 60 days. Agenda Item 5 – Federal Energy Regulatory Commission Report Mr. John Rogers provided an update on FERC activities:

• On February 15, the Commission issued Order No. 890, revisions to the Commission’s regulations and the pro forma open access transmission tariff adopted in Order No. 888 and noted that SPP’s initial compliance filing was due May 29. On April 11, the Commission extended by 60 days to July 13, certain compliance requirements of non-RTO/ISO transmission providers.

• On March 15, FERC approved 83 NERC Reliability Standards. • Accepted eight NERC Regional Entity Delegation Agreements on April 19, 2007. SPP’s

agreement was accepted with some modifications and clarifications. • Two significant cost allocation orders were issued:

o Accepted California ISO’s mechanism for financing facilities to interconnect “location-constrained renewable resources” such as wind, geothermal, and solar to the grid.

o Adopted PJM’s cost allocation plan in which all new facilities that operate at or above 500 kV, both reliability and economic, should be priced on a postage stamp/region-wide basis.

Agenda Item 6 – Markets and Operations Policy Committee Report Mr. John Olsen provided the Markets and Operations Policy Committee (MOPC) report (MOPC Report – Attachment 6). Mr. Olsen announced that Mr. Bill Dowling (Midwest Energy) will serve as vice chair of MOPC. He asked Mr. Dennis Reed to present the Regional Tariff Working Group (RTWG) report regarding unintended consequences (Unintended Consequences Report – Attachment 7). Mr. Reed stated that there were no unintended consequences identified with the potential exception of one project in NW Arkansas. SPP Staff and AEP questioned results associated with Fayetteville 69 to 161 kV Conversion Project. SPP Staff performed a sensitivity analysis and determined that:


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• MISO LODF approach does not consider the impact of losses on MW-MI allocations, but a 1% minimum LODF cut-off is also incorporated at MISO

• Base Plan Projects impacts on area losses are not insignificant in many circumstances, therefore

Lossless DC is not appropriate

• Final MW-MI allocations need to remove possible influence due to changes in losses resulting from a shift in area slack bus due to change in area losses which can be material for many projects

• Final MW-MI allocations should be based on system participation for all generators within a

Control Area, not a single slack bus in each area or the system swing bus in the solution

• No tariff changes are necessary at this time. The change in the manner losses are handled can be implemented without changes to the SPPOATT

Mr. Olsen presented MOPC action items: Letter of Credit Requirements: Section 19.4 and 32.4 require the transmission customer to supply a Letter of Credit (LOC) or cash to cover the cost of any transmission upgrades (LOC Recommendation – Attachment 8). The RTWG passed the following proposal:

1. To modify Sections 19.4 and 32.4 to only require transmission customers to have an LOC or other credit instrument if the costs of the upgrades are directly assigned to them.

2. To limit the LOC to only the cost of the upgrade allocated to the customer through the aggregate study process.

3. To reinsert the pro-forma language into Sections 19.4 and 32.4 allowing SPP to negotiate other forms of credit acceptable to it.

4. If an LOC is required, allow SPP to increase and decrease the LOC amount for each customer based upon the expected expenditures or remaining revenue stream.

The MOPC recommends that the Board of Directors accept the proposed tariff language changes to Sections 18.4 and 32.4. Mr. Skilton moved to approve the MOPC recommendation. Mr. Brown seconded the motion. The Members were in unanimous favor. The motion passed. Mr. Skilton commended Mr. Reed for his analysis. Network Secondary Services: The Market Monitoring Unit (MMU) has found no evidence of deliberate abuse concerning the use of secondary Network Integration Transmission Service (NITS), but there is potential (Secondary Services Recommendation – Attachment 9). The MOPC recommends that the Board accept the proposed tariff language changes to Section 28.4 limiting the amount of secondary network service to:

1. 200 MW or 125% of the NITS Customer’s average maximum usage on four separate days

2. Shall not exceed 110% of the NITS customer’s peak load Mr. Brown moved to approve the MOPC recommendation. Ms. Bernard seconded the motion. The Members were in unanimous favor. The motion passed. Staff is to provide a report to the Board in six months to assess the results of modifications to Section 28.4 of the tariff. Waiver Requests: Arkansas Electric Cooperative Corporation (AECC) and Oklahoma Municipal Power Authority (OMPA) have requested waivers based on Section III.C.2.ii of Attachment J of the SPP Tariff for a reservation of 20 years and the commitment to the life of the Turk Power Plant (Waiver Requests Recommendation – Attachment 10). The MOPC approved SPP Staff recommendation and seeks


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Board approval to provide waivers of such extent that projects required for the AECC and OMPA new designated resources are fully Base Plan funded. Mr. Brown moved the recommendation. Ms. Bernard seconded the motion. The Members were in favor with Mr. Richard Spring in opposition. The motion passed. It was suggested that staff provide a proposal for changes designed to shorten the aggregate study process and be performed prior to waiver requests to allow more accuracy. PRR’s 124, 140, and 143: The following tariff changes were recommended (PRR 124, 140, and 143 Recommendations – Attachment 11):

• PRR 124 - changed posting “annual hours of constraint” by resource rather than flowgate. • PRR 140 - extended issuance of a final settlement statement from 45 to 47 days after operating

day. • PRR 143 - modified that only scheduled market flow is assigned to Firm transmission priority

rather that all market flow. The MOPC recommends that the Board accept the proposed tariff language changes to implement PRR 124, 140, and 143. Mr. Brown moved to approve the MOPC recommendation. Mr. Martin seconded the motion. The Members were in unanimous favor. The motion passed. PRR 137: SPP is to file tariff language with FERC by May 2 permitting participation in the energy market by external generators (PRR 137 Recommendation – Attachment 12). The recommended modifications and clarifications to PRR 137 are:

1. Market Participants (MP) with external generators will register a sink Settlement Location within an SPP energy market Balancing Authority (BA). This sink Settlement Location will be used in the evaluation of Transmission Reservation requests. This sink Settlement Location will not have any energy market settlement charges.

2. Point-to-point Transmission Service within SPP must be utilized to schedule to a sink Settlement Location registered by the MP with external generation.

3. The Tariff will specifically exclude Non-firm Transmission Reservations for external generators from incurring Transmission Reservation Service charges.

4. Available Transmission Capability (ATC) is appropriately reduced, pursuant to Criteria 4, for those Transmission Reservations made to facilitate external generator participation in the energy market. In SPP’s determination of these impacts, consideration will be given to historical usage of transmission service, thereby utilizing the lower of historical usage or the Transmission Reservation as per Criteria 4.

5. SPP Business Practices regarding the definition of competing requests for purposes of exercising preemption rules would be changed to define requests for Transmission Service to the same POD as competing. This allows for a higher priority Transmission Request to preempt a lower priority Transmission Request when there is insufficient ATC to accept both Requests for Transmission Service with similar impacts on flowgates.

6. SPP Criteria modifications will be requested, if determined necessary, to allow the request for assistance upon the loss of a non-firm schedule.

7. SPP will calculate the aggregate impact of the external generators on each BA NSI and include this information in updates to the BA.

8. The BA settlement agreement addresses recovery for a BA receiving penalties or sanctions resulting from SPP’s actions or inactions.

Mr. Brown moved to approve the PRR 137 recommendation. Mr. Skilton seconded the motion. Following discussion, Mr. Brown withdrew his motion. The group agreed that SPP should file for an extension and that the working groups should work expeditiously to find solutions to the remaining pending issues. A teleconference will be scheduled in mid June to address this topic. Tariff language will be drafted and presented at the July Board meeting for approval.


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Mr. Olsen concluded his report with informational topics including the winter storms and future market designs. Agenda Item 7 – Strategic Planning Committee Report Mr. Richard Spring provided the Strategic Planning Committee report (SPC Report – Attachment 13). At the April 12 meeting, the SPC heard updates on MOPC activities, FERC Orders 890 and 683, and the NERC Regional Entity Delegation Agreement. Other issues addressed were:

• Organizational Effectiveness Action Plan – Mr. Carl Monroe is working on reorganizing some of the SPP organizational groups.

• Demand response – FERC Order approving its Energy Imbalance Market requires SPP to incorporate demand response into its market within 6 months of start-up.

• Prioritization of the SPP Strategic Plan – SPC recommended a task force be developed administratively reporting to the SPC to develop and recommend policies for transmission expansion/economic upgrades. Members of the task force are: Mr. Mel Perkins (OG&E), Chair; Mr. Ricky Bittle (AECC); Ms. Cindy Holman (OMPA); Mr. Kelly Harrison (Westar); Mr. Charles Locke (KCPL); Mr. Larry Holloway (KCC); Mr. Carl Huslig (ITC Great Plains); and Mr. Les Dillahunty (SPP).

Agenda Item 8 – Compliance Committee Report Mr. Josh Martin provided the Compliance Committee report. The committee met in Washington D.C. on March 29 and reviewed several items:

• SPP hosted a Compliance Workshop February 13-14 in Tulsa with record attendance. • Eleven Members achieved 100% compliance during 2006.

o Arkansas Electric Cooperatives o Empire District Electric o City of Independence, KS o City of Lafayette, LA o Oklahoma Municipal Power Authority o Southwestern Power Administration o West Plains Electric o Westar o City of Yazoo City o Kansas Electric Power Cooperatives o Southwest Power Pool Reliability Coordinator

• No new requests for inquiry were submitted to the Market Monitor during this period and there are no outstanding requests for inquiry. There have been requests for clarification related to the Market Operations, which will be handled on an ad hoc basis until volume dictates a more formalized approach.

• Following the meeting, Mr. Martin, Ms. Bernard, and Ms. Stacy Duckett were able to meet with the Director of the Office of Enforcement and the Director of Energy Market Oversight at FERC.

Mr. Craig Roach (Boston Pacific) provided an update on the EIS Market performance in March, the second month of operation. Mr. Roach reported that there was robust participation, 1.1M MW sold in March; SPP prices were down as was volatility, which meant that revenue was down; and the severity of transmission congestion was down.


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Agenda Item 9 – Human Resources Committee Report Mr. Quentin Jackson provided the Human Resources Committee report (HRC Report – Attachment 14). Mr. Jackson announced that Ms. Malinda Stevens, staff secretary for the Human Resources Committee, has been promoted to Director of Corporate Services. Mr. Jackson moved as recommended by the HR Committee, that Southwest Power Pool Board of Directors approve establishment of a Roth option as part of the SPP 401(k) plan. Ms. Bernard seconded the motion. The Members were in unanimous favor. The motion passed. The committee has arranged for the Hay Group, Inc. to conduct a compensation survey. They will be conducting interviews with SPP officers and directors in Little Rock on May 3 and 4. A complete report will be presented to the HRC June 13. The last survey conducted by the Hay Group was three years ago.

The SPP employee base is stabilizing with current full time employees at 257 and 2 part time employees. Year to date 21 employees have been hired with 31 positions currently open.

The committee reviewed benefit plans, considered defined benefit SERP recommendation to address deficiencies in SPP Retirement Plans, reviewed the 2006 Performance Compensation process, and planned a retreat for June 13-14 in Little Rock.

Agenda Item 10 – Finance Committee Report Mr. Harry Skilton provided the Finance Committee report (Finance Committee Report & Recommendations – Attachment 15). Mr. Skilton reviewed the 2006 Financial Audit from BKD, LLC. The audit opinion was unqualified with no material weaknesses in process or procedures. Significant improvement was noted in the audit adjustments and management controls. Mr. Skilton moved that the SPP Board of Directors accept in its entirety the 2006 audit report. Mr. Altenbaumer seconded the motion. The Members were in unanimous favor. The motion passed. The Finance Committee confirmed a policy of funding capital expenditures with debt financing and approved the 2007 financing. Mr. Skilton moved that the SPP Board of Directors resolves to borrow $30 million from US Bank on terms indicated in US Bank’s term sheet and SPP Board of Directors resolves to borrow $20 million from JP Morgan Chase on the terms indicated in the JP Morgan Chase term sheet. The SPP Board of Directors authorizes the SPP President and CFO to jointly execute all evidence of the above indebtedness. Mr. Altenbaumer seconded the motion. The Members were in unanimous favor. The motion passed. Mr. Skilton moved that the SPP staff is directed to submit a filing to the Arkansas Public Service Commission requesting authority to issue $30 million in term financing and $20 million in revolving notes. Mr. Martin seconded the motion. The Members were in unanimous favor. The motion passed. Mr. Skilton reported on Credit Task Force (CTF) actions. The task force approved a change in Credit Policy such that suspension of unsecured credit limit is not triggered if payment is received by cure date, reduction in cure period for transmission service from 10 days to 3 days, and other changes to clarify intent. Mr. Skilton reviewed the Market Settlement timeline. Mr. Skilton moved:

• SPP Board of Directors direct Markets and Operations Policy Committee to make necessary changes to protocols to allow issuance of initial settlement statements less than 7 days after operating date.


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• Initial settlement statement timeline changes should be provided to Finance Committee in advance of September 19, 2007 meeting.

Mr. Altenbaumer seconded the motion. Following discussion, Mr. Eckelberger moved to amend the motion to read “determine cost benefit and make necessary changes.” Mr. Brown seconded the motion. The Members were in favor with Ms. Trudy Harper in opposition. The motion passed. A vote was called on the original motion. The Members were in favor with Ms. Trudy Harper in opposition. The motion passed. Mr. Skilton provided an update on the SAS70 Type II Audit. Price Waterhouse Cooper performed a preliminary review beginning the end of April which indicated many deficiencies. The audit will begin May 1 for a six month period. It is hoped to rectify many deficiencies early in the process. We may have a qualified opinion in October. Agenda Item 11 – Corporate Governance Committee Report Mr. Nick Brown provided the Corporate Governance Committee (CGC) report. The CGC has started the nomination process for 2007. Term expirations for this year are:

Board of Directors: Ms. Phyllis Bernard and Mr. Quentin Jackson Members Committee: Mr. Tom Stuchlik, Mr. Stuart Solomon, Mr. Gary Voigt, Mr. Jeff Knottek, and Mr. Rob Janssen

Ms. Bernard and Mr. Jackson have been re-nominated for another term. The Members Committee members have indicated a willingness to be re-nominated. If there are additional candidates, please provide names to Ms. Stacy Duckett or to Mr. Brown prior to the CGC meeting on May 10. The CGC is to nominate trustees for the Regional Enitity to be selected by the Membership. These trustees will oversee the development of enforceable standards and enforce compliance. Names for consideration are: Mr. John Marschewski, Mr. Dave Christiano, and Mr. Gerry Burrows. Mr. Rob Janssen nominated another individual, Mr. Larry Grundmann, and provided background. Nominations will also be allowed from the floor at a Special Meeting of Members in mid June. Agenda Item 12 – Policy Discussion: Demand Response Mr. Brown encouraged all to think about demand response and share any comments. Agenda Item 13 – Summary of Action Items Ms. Stacy Duckett provided a summary of action items:

1) Schedule a special meeting of the BOD/MC and a special meeting of the Membership in June to address SPP Bylaws revisions and elect the RE Trustees.

2) Staff is to present a proposal for changes designed to shorten the Aggregate Study process. Any comments/suggestions should be provided to Les Dillahunty.

3) Staff is to provide a report to the BOD/MC in six months of the results of the revisions to Section 28.4 of the SPP OATT regarding secondary network service.

4) The MOPC is to develop a revised proposal for market access for External Generators for consideration at the special meeting of the BOD/MC in June

Future Meetings The next Board of Directors meeting is an educational meeting June 11-12 in Little Rock. A special teleconference meeting of the BOD/MC and the Membership will be scheduled in mid June. The next regularly scheduled business meeting is July 24 in Kansas City.


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Adjournment With no further business, Mr. Eckelberger thanked everyone for participating and adjourned the meeting at 2:45 p.m. Stacy Duckett, Corporate Secretary

Southwest Power Pool BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING

April 24, 2007 The Skirvin Hilton Hotel – Oklahoma City, OK

• A G E N D A •

8:30 a.m. – 3:00 p.m. CDT

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

2. Review of Past Action Items ........................................................... Ms. Stacy Duckett

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

a. Introduction of Policy Discussion: Demand Response

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

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

6. Markets and Operations Policy Committee Report .............................. Mr. John Olsen

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

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

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

10. Finance Committee Report ...............................................................Mr. Harry Skilton

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

12. Policy Discussion: Demand Response .............................................. Mr. Nick Brown

13. Summary of Action Items............................................................... Ms. Stacy Duckett

14. Future Meetings.......................................................................... Mr. Jim Eckelberger

a. June 11 – 12 Little Rock

b. July 24 Kansas City

c. October 30 Tulsa

d. December 11 Dallas

From: Rick Tyler [mailto:[email protected]] Sent: Monday, May 07, 2007 11:11 AM To: Stacy Duckett Cc: Cheryl Robertson; Brian, David Subject: RE: SPP Proxy Stacy, please allow David Brian to have my proxy for the SPP Board and Members Committee Meeting held on April 24 held in OKC. Thanks.



Hilton Palacio Del Rio, San Antonio, TX

January 30, 2007

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

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

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

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

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

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

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

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

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

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

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

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

MINUTES NO 110

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Hilton Palacio Del Rio, San Antonio, TX

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

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

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

SPP Board of Directors/Members Committee Minutes January 30, 2007

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

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

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

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

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

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

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

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

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

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


4

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

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

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

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

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

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

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

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

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


5

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

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

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

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

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


6

Brown moved to approve the following recommendation:

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

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

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

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

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

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

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

required. c. The TWG supports this recommendation.

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

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

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


7

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

SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT

1Q 2007

SUMMARY

1Q 2007 4Q 2006 3Q 2006 2Q 2006 1Q 2006

Tariff Administration Service, Fees & Assessments

$17.7M (YTD)

$57.3M $42.8M $28.2M $14.6M

Operating Expenses $18.6M (YTD)

$64.1M $45.9M $29.1M $13.1M

Operating Cash Flow $2.8M (YTD)

$10.1M $0.9M $6.2M $6.1M

Cash on Hand $31.0M

(03/31/07)$28.2M $25.8M $35.6M $38.9M

TLR Events 282 67 244 160 61

Tags (daily average) 433 416 543 582 432

Transmission Service Requests 47,508 36,090 51,695 48,564 36,567

Transmission Service Study Queue

346 requestsfor studies

434 requests

439 requests

316 requests 110/103

Generation Interconnection Queue

61 requests 52requests

45 requests

45 requests

43requests

Stakeholder Meetings 33 22 30 62 48

FERC/State Commissions Dockets Pending

99 83 46 44 43

Legal Matters Pending 0 0 0 2 2

Executive Industry Activities 29 29 27 40 29

Number of Members 47 47 47 46 46

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

5 (2006) 7 (2006)

Staff 256 245 235 220 188


1Q 2007

SPP FINANCIAL STATEMENTS 1ST QUARTER DISCUSSION ALL DOLLAR VALUES IN THOUSANDS

SPP reported net income of $2,717 on revenues of $21,539 through the first three months of FY’07 as compared to net income of $1,580 on revenues of $15,066 for the same period in FY’06. Gross revenues are tracking closely to budget although net income exceeds budget by $3,255. REVENUES Administrative fee collections increased 31% from $11,234 in 2006 to $14,699 in 2007. This increase is primarily due to SPP’s administrative rate increase to 19¢/MWh effective January 2007 from 16¢/MWh established in January 2005. Billing units for the first three months of 2007 increased to 77,362,000 MWh from 70,209,000 MWh in 2006. Tariff administrative fees account for 68% of SPP’s total revenue stream as compared to 75% for the same period in FY’06. This decrease is primarily due to growth in Contract Services revenue as a percentage of SPP’s total revenue. Gross transmission sales YTD’07 increased to $93,864 from $65,285 for the same period in 2006. This increase is due to expected internal load growth as well as the addition of Aquila and Sunflower transmission facilities to the SPP tariff. The remainder of SPP’s revenues are categorized as follows:

YTD’07 YTD’06 Budget’07

Fees and Assessments $3,016 $3,065 $2,870

Contract Services 3,579 360 3,868

Miscellaneous Income 245 408 439

Fees and Assessments: The variance to budget reflects an increase in the Schedule 12 billing units (i.e. actual load). Contract Services: Implementation of the Entergy and LG&E contracts had not occurred at this point in 2006. The variance to the budget is primarily due to the delay in implementation of the Weekly Procurement Process associated with the Entergy contract. Miscellaneous Income: The decline in 2007 results from lower than anticipated study activities in the first quarter.


1Q 2007 EXPENSES Assessments and Fees, Personnel Expenses, and Outside Services represent 72% of SPP’s total expenses YTD’07 as compared to 77% for the same period in 2006. The percentage has declined due to growth in depreciation associated with the EIS Market asset. Assessments and Fees are pass-through costs allocated to SPP in support of FERC operations; SPP management has no control over these expenditures. 2006 actuals also include pass-through costs for NERC operations; however NERC has altered their funding policies and will now bill regional entity customers directly beginning in 2007. Personnel Expenses totaled $8,074 through 1Q’07 as compared to $5,760 for the same period in 2006. Actual expenses for the period are 12% below budget. Included in these expenses is the addition of 47 net staff (total staff as of March 31, 2006 was 213) and an increase in pension plan funding of $221 over the same period in 2006. There are currently 36 open positions. Outside Services expenditures provide for the support and operation of many of SPP’s specialized systems, most notably the commercial operations system which settles the Energy Imbalance Service (EIS) market. Through the first three months of 2007, SPP incurred $3,375 in outside services expenditures as compared to $2,660 in the prior year period, and a budgeted amount of $3,281. The additional expenditures have provided enhanced project management support for the EIS market project. LIQUIDITY SPP’s liquidity has steadily declined over the past year as cash has been deployed to meet capital project requirements and debt amortization obligations. SPP generated $6,822 in cash from operations and $5,140 from financing during the first three months of 2007 which, along with existing cash balances, was used to fund $4,219 in capital expenditures and $5,000 in principal payments on long-term debt. SPP maintains an $8,000 working capital facility with a commercial bank to fund any short-term cash shortfalls. SPP advanced $4,000 from this facility in 1Q’07.

1Q’07 4Q’06 1Q’06

Unrestricted Cash $16,393 $12,512 $23,435

Current Ratio .83 .80 1.32


1Q 2007 CAPITALIZATION SPP’s balance sheet is highly leveraged as a result of: 1) SPP’s policy to fund capital projects with debt financing, and 2) a rate setting process intended to fund only budgeted expenditures. Historical spending below budget has served to stabilize Member’s Equity and the debt/capitalization ratio.

1Q’07 4Q’06 1Q’06

Members’ Equity $15,592 $12,875 $15,347

Long-Term Debt $25,140 $25,000 $30,000

Debt/Capital 62% 66% 66%

Total Liabilities/Members’ Equity 4.62 5.54 4.30

Development of market functionality as well as other project initiatives will likely result in SPP entering the debt market during 2Q’07.

Southwest Power PoolBalance Sheet

As of March 31, 2007

03/31/07 12/31/06 03/31/06($000)

ASSETS Current Assets Cash & Equivalents $16,393 $12,512 $23,435 Restricted Cash Deposits 14,565 15,703 15,508 Accounts Receivable (net) 4,649 5,702 5,272 Other Current Assets 2,997 2,701 3,306

----------------------- ----------------------- ----------------------- Total Current Assets 38,604 36,618 47,521 Total Fixed Assets 47,348 46,014 33,128 Total Other Assets 1,610 1,550 686

----------------------- ----------------------- -----------------------TOTAL ASSETS $87,562 $84,181 $81,335

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

LIABILITIES & EQUITY Liabilities Current Liabilities Accounts Payable (net) $3,270 $4,140 $3,271 Customer Deposits 14,565 15,703 15,508 Current Maturities of LT Debt 10,000 10,000 5,000 Other Current Liabilities 18,718 16,206 12,210

----------------------- ----------------------- ----------------------- Total Current Liabilites 46,553 46,050 35,988

----------------------- ----------------------- ----------------------- Long Term Liabilities 7.50% Senior Notes - 2008 5,000 5,000 4.78% Senior Notes - 2011 20,000 20,000 25,000 US Bank Note - 2027 5,140 Other Long Term Liabilities 277 257

----------------------- ----------------------- ----------------------- Total Long Term Liabilities 25,417 25,257 30,000

----------------------- ----------------------- ----------------------- Net Income 2,717 (893) 1,580 Members' Equity 12,875 13,767 13,767

----------------------- ----------------------- ----------------------- Total Members' Equity 15,592 12,875 15,347

----------------------- ----------------------- -----------------------TOTAL LIABILITIES & EQUITY $87,562 $84,181 $81,335

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

Southwest Power PoolIncome Statement

For the Three Months Ending March 31, 2007

Actual YTD Actual YTD Actual YTD Budget YTD2007 2006 Variance 2007 2007 Variance

($000)

Ordinary Income/Expense Income Tariff Administration Service $14,699 $11,234 $3,465 $14,699 $13,711 $988 Fees & Assessments 3,016 3,065 (49) 3,016 2,870 146 Contract Services Revenue 3,579 360 3,220 3,579 3,868 (288) Miscellaneous Income 245 408 (163) 245 439 (195)

-------------------- -------------------- -------------------- -------------------- -------------------- -------------------- Total Income 21,539 15,066 6,473 21,539 20,888 651

-------------------- -------------------- -------------------- -------------------- -------------------- -------------------- Expense Salary & Benefits 8,074 5,760 2,314 8,074 9,223 (1,149) Employee Travel 205 149 56 205 303 (98) Administrative 399 352 47 399 480 (81) Assessments & Fees 2,033 1,952 81 2,033 2,075 (42) Meetings 112 96 17 112 235 (122) Communications 584 631 (47) 584 720 (136) Leases 210 180 30 210 216 (7) Maintenance 706 666 40 706 1,150 (444) Services 3,375 2,660 716 3,375 3,281 94 Regional State Committee 40 42 (2) 40 142 (103) Depreciation & Amortization 2,894 698 2,197 2,894 3,116 (221)

-------------------- -------------------- -------------------- -------------------- -------------------- -------------------- Total Expense 18,632 13,186 5,447 18,632 20,941 (2,309)

-------------------- -------------------- -------------------- -------------------- -------------------- --------------------Net Ordinary Income 2,907 1,881 1,026 2,907 (53) 2,960

-------------------- -------------------- -------------------- -------------------- -------------------- --------------------Other Income/Expense Other Income Interest Income 261 263 (2) 261 339 (78)

-------------------- -------------------- -------------------- -------------------- -------------------- -------------------- Total Other Income 261 263 (2) 261 339 (78) Other Expense Interest Expense 451 564 (114) 451 824 (374)

-------------------- -------------------- -------------------- -------------------- -------------------- -------------------- Total Other Expense 451 564 (114) 451 824 (374)

-------------------- -------------------- -------------------- -------------------- -------------------- --------------------Net Other Income (Expense) (190) (301) 112 (190) (485) 295

-------------------- -------------------- -------------------- -------------------- -------------------- --------------------Net Income (Loss) $2,717 $1,580 $1,138 $2,717 ($538) $3,255

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

Southwest Power PoolStatement of Cash Flows


YTD

OPERATING ACTIVITIES Net income $2,717 Adjustments to reconcile net income (loss) to new cash provided by operations: Depreciation 2,884 Amortization 10 Changes in assets and liabilities: Accounts receivable 1,053 Accrued revenue 79 Prepaid expenses (375) Accounts payable (870) Other current liabilities (1,487) Change in derivative liability 20 Customer deposits (1,138) Other assets (70)

-----------------------Net cash provided by operating activities 2,822

INVESTING ACTIVITIES Purchase of property and equipment (4,219)

-----------------------Net cash used by investing activities (4,219)

FINANCING ACTIVITIES Repayment on 7.5% Senior Notes - 2008 (5,000) Issuance of US Bank Mortgage Notes 5,140 Advance on line of credit 4,000

-----------------------Net cash provided by financing activities 4,140

Net cash increase for the period 2,743

Cash at beginning of period 28,215-----------------------

Cash at end of period $30,958=============

Southwest Power Pool2007 Foundation Actuals vs. Budget


YTD YTD Variance Full YearActuals Budget Fav/(Unfav) Budget

Revenues ($M): Tariff Fees & Member Assessments 17,008 15,901 1,107 63,603 Other Member Services 245 206 38 1,328 Total Revenues 17,252 16,107 1,145 64,931

Operating Expenses ($M): Salaries & Benefits 6,364 7,156 792 28,657 Other Expense 8,817 9,575 758 38,376 Total Operating Expenses 15,181 16,731 1,550 67,033

Capital Expenditures 619 3,116 2,497 5,459

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

billable MW/h of 7% (includes FERC fees)• Other operating expenses are favorable to budget primarily due to delay in depreciation associated

with the Imbalance Market system• CapEx expenditures trail budget due to delay in computer hardware “refresh” activity versus budget

Southwest Power Pool2007 Contract Services Actuals vs. Budget



Revenues ($M): Tariff Fees & Member Assessments 0 0 0 0 Other Member Services 3,579 3,868 (288) 15,470 Total Revenues 3,579 3,868 (288) 15,470

Operating Expenses ($M): Salaries & Benefits 1,399 1,405 7 5,593 Other Expense 318 353 34 1,323 Total Operating Expenses 1,717 1,758 41 6,916

Capital Expenditures 172 689 517 709

Notes• Contract Services revenue is unfavorable to budget primarily due to delay in Weekly Procurement

Process implementation

Southwest Power Pool2007 Center of Excellence Actuals vs. BudgetFor the Three Months Ending March 31, 2007


Revenues ($M): Tariff Fees & Member Assessments 0 0 0 0 Other Member Services 0 0 0 281 Total Revenues 0 0 0 281

Operating Expenses ($M): Salaries & Benefits 22 55 33 221 Other Expense 5 15 10 60 Total Operating Expenses 27 70 43 281


Notes• Executive Director of Center of Excellence was hired effective March, 2007

Southwest Power Pool2007 CIP Standards Actuals vs. Budget






Notes• CIP resource was hired effective March, 2007

Southwest Power Pool2007 Reliability Operations Center Actuals vs. Budget




Operating Expenses ($M): Salaries & Benefits 0 90 90 361 Other Expense 0 862 862 3,449 Total Operating Expenses 0 953 953 3,811

Capital Expenditures 1,922 5,123 3,201 5,534

Notes• Operating expenses are favorable to budget for first quarter 2007 since building was not

operational until April 9, 2007

• The project is on track to spend the Board approved capital amount of $11,902

Southwest Power Pool2007 EMS Upgrade Actuals vs. Budget






Notes• Preliminary activity associated with the project has begun, however financial activity has not

Southwest Power Pool2007 Regional Entity Actuals vs. Budget



Revenues ($M): NERC Revenue 707 680 27 2,721 Training Fees 0 115 (115) 460 Total Revenues 707 795 (88) 3,181

Operating Expenses ($M): Salaries & Benefits 262 428 167 1,713 Other Expense 446 367 (79) 1,468 Total Operating Expenses 707 795 88 3,181


Notes• Compliance Engineer position expected to be hired in 2nd quarter

• Delay in delegation agreement approval from FERC has slowed Regional Entity activity

Southwest Power Pool2007 EIS Markets & Dispute Resolution Actuals vs. Budget



Revenues ($M): Tariff Fees & Member Assessments 0 0 0 0 External Generators 0 118 (118) 473 Total Revenues 0 118 (118) 473

Operating Expenses ($M): Salaries & Benefits 20 59 39 235 Other Expense 1,162 1,005 (157) 3,491 Total Operating Expenses 1,181 1,064 (118) 3,726

Capital Expenditures 1,506 1,517 11 5,842

Notes• External Generator capability continues to be developed. May not collect revenue.

• Higher engagement of consultants due to delay in EIS implementation and maintenance of resources


1Q 2007

RELIABILITY COORDINATION

1Q07 v. 1Q06 shows an increase.

1Q07 v. 7Q06 shows an increase in MWh curtailed due to TLR.

TLR Events per Quarter

0

50

100

150

200

250

300

# of

Eve

nts

SPP 282 67 244 160 61 1Q-07 4Q-06 3Q-06 2Q-06 1Q-06

MWh Curtailed due to TLR

0

20000

40000

60000

80000

100000

120000

1Q-07 4Q-06 3Q-06 2Q-06 1Q-06

MW

h Firm Non-Firm


1Q 2007

SCHEDULING

1Q07 v. 1Q06 shows a slight increase in the number of tags processed.

Daily Average Tags Processed

0

100

200

300

400

500

600

700

Num

ber o

f Tag

s

SPP 433 416 543 582 432 1Q-07 4Q-06 3Q-06 2Q-06 1Q-06


1Q 2007

TARIFF ADMINISTRATION

1Q07 v. 1Q06 shows an increase in total transmission service requests.

Total Requests Submitted

0

10000

20000

30000

40000

50000

60000

SPP 47508 36090 51695 48564 36567 1Q-07 4Q-06 3Q-06 2Q-06 1Q-06


1Q 2007

1Q07 v. 1Q06 shows a decrease in percentage of transmission service requests confirmed.

% of Total Requests that are Confirmed

0%

10%

20%

30%

40%

50%

60%

70%

SPP 36% 58% 47% 48% 56% 1Q-07 4Q-06 3Q-06 2Q-06 1Q-06


1Q 2007

QUEUE STATUS REPORT Transmission Service Request Queue Number of study requests = 346, representing 29,285 MW Number of study requests for non-DC Tie = 231, representing 17,583 MW Number of DC Tie requests = 115, representing 11,702 MW - These requests cannot be processed due to impending DC Tie competition. During the same period last year Number of study requests for non-DC Tie = 81, representing 5,915 MW. Number of DC Tie requests = 29, representing 2,087 MW - These could not be processed due to impending DC Tie competition. Generation Interconnection Queue Number of active requests = 61, representing 16,570 MW • Number of wind requests = 44, representing 8,327 MW • Number of fossil fuel requests = 17, representing 8,243 MW Number of requests with Interconnection Agreement pending = 7 Interconnection Agreements signed during 2007 = 5 (Wind – 1 for 200 MW; Fossil – 4 for 1044 MW not included above) During the same period last year, there are 43 requests in process (23 wind; 20 fossil fuel) representing 11,448 MW (3,635 MW wind; 7,558 MW fossil fuel). There were 12 Interconnection Agreements pending.


1Q 2007

SPP Regulatory Affairs Activities First Quarter - 2007

SPP Regulatory Staff experienced continued growth in its caseload during the first

quarter of 2007, with a total of 124 cases being tracked at the federal and state levels. SPP is currently involved in 106 dockets at the Federal Regulatory Commission and a combined total of 18 dockets at the state utility commissions of Arkansas, Louisiana, Missouri and Texas.

A summary of significant issues undertaken by SPP Regulatory Staff in 2006 is set out

below, followed by an update for the first quarter of 2007. A detailed report can be accessed at: SPP FERC/State Dockets.

Regulatory Summary - 2006

1. Reevaluation of FERC’s Annual Electric Assessment 2. FERC Rulemaking Proceedings

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

b. Certification of the ERO and Procedures for the Establishment, Approval and Enforcement of Electric Reliability Standards

c. Docket No. RM06-4: Promoting Transmission Investing through Pricing Reform d. Docket No. RM06-8: Long-Term Firm Transmission Rights in Organized

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

Bulk Power System f. Docket No. RM07-3: Facilities Design, Connections and Maintenance Reliability

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

3. FERC Administrative Proceeding a. FERC Federal-State Joint Boards on Security Constraints and Economic Dispatch

4. FERC ERO Rules and Organizational Filings a. NERC Filing of Version 5 Reliability Standards Development Procedure b. NERC Filing of the 2007 Business Plans and Budgets

5. FERC Electric Rate Filings of Interest a. Docket No. ER06-451-000: EIS Market implementation b. Docket No. ER06-729: Attachment M Revisions c. Docket Nos. ER03-765 and ER07-371: Reactive Compensation

d. Docket No. ER06-1362: Attachment X – Transmission Expansion Plan and Credit Policy

e. Docket No. EL07-6: FERC Inquiry Regarding Gas-Electric Coordination Issues 6. Louisiana and New Mexico Appeal for Review of the SPP RTO Orders (Case No. 04-

1398) – Dismissed October 13, 2006; 7. Addressing First Three Waiver Requests under Attachment J


1Q 2007 8. Approval of Entergy’s ICT Proposal 9. Arkansas Regulatory Proceedings

a. Docket No. 04-137-U b. Docket Nos. 05-021-U, 06-077-U and 06-142-U

10. Missouri Regulatory Proceedings a. Docket Nos. EO-2006-0141 and EO-2006-0142

11. Kansas Regulatory Proceeding a. Docket No. 06-SPPE-202-COC

12. Texas Regulatory Proceeding a. Texas CREZ Rule: Project No. 31852

13. SPP EHV Overlay Assessment Regulatory Update - First Quarter 2007

1. Reevaluation of FERC’s Annual Electric Assessment On March 8, 2007, members of the RLC subcommittee responsible for this issue met in Columbus, Ohio with Scott Hempling, Director of the National Regulatory Research Institute (“NRRI”). As a result of that meeting, the subcommittee enlisted the services of Jeff DiSciullo of Wright & Talisman to review all of the information prepared by the RLC and Scott and provide a fresh perspective of the problem and the proposed solutions. Jeff provided a draft last week of his reassessment, and that has been forwarded to the RLC subcommittee members for their review. 2. FERC Rulemaking Proceedings

a. Docket Nos. RM05-17 and RM05-25: Order No. 888 NOPR

On February 16, 2007, the Commission issued final rule Order No. 890, amending the regulations and the pro forma OATT adopted in Order Nos. 888 and 889 to ensure that transmission services are provided on a basis that is just, reasonable and not unduly discriminatory or preferential. Order No. 890 impacts SPP by requiring that SPP: conform the SPP OATT to a new pro forma template, post more information online, comply with modified planning standards and monitor the NERC/NAESB process that will incorporate new reliability standards.

Several requests for rehearing/appeal/clarification of Order No. 890 have been filed with the Commission.

b. Docket No. RM06-4: Promoting Transmission Investing through Pricing Reform In January of 2007, several requests for clarification, rehearing or appeal of Order No.

679-A were filed with the Commission, and on February 21, the Commission granted rehearing of the order.


1Q 2007

c. Docket No. RM06-8: Long-Term Firm Transmission Rights in Organized Electric Markets

Rehearing of Order No. 681-A was granted by the Commission on January 17, 2007. ISO-NE, CAISO and the NYISO have filed compliance proposals in this proceeding. Proposals were due to the Commission by January 29, 2007.

d. Docket Nos. RM06-16 and RM06-22: Mandatory Reliability Standards for the Bulk Power System

Several rulemaking comments have been filed in Docket No. RM06-22, with SPP filing

comments on February 12, 2007. The ISO/RTO Council (“IRC”), PJM, and ISO-NE also filed comments.

Numerous rulemaking comments and supplemental comments were filed in Docket No. RM06-16, as well. Notably, comments were filed by the ISO/RTO Council; MISO and PJM; CAISO; ISO-NE; and PJM.

On February 23, 2007, NERC requested that the Commission approve violation risk factors for Version 0 reliability standards. .

On March 16, 2007, the Commission issued Order No. 693 in Docket No. RM06-16-000, approving 83 of 107 proposed Reliability Standards, 6 of the 8 proposed regional differences, and the Glossary of Terms Used in Reliability Standards developed by NERC. As the ERO, NERC must submit “significant improvements” to 56 of the 83 Reliability Standards being approved. The remaining 24 standards are pending at the Commission until further information is provided.

The Final Rule adds regulations stating applicability to all users, owners and operators of

the Bulk-Power System within the United States (other than Alaska or Hawaii) and requires that each Reliability Standard identify the subset of users, owners and operators to which that particular Reliability Standard applies. All approved Reliability Standards are to be maintained on the ERO’s Internet website for public inspection.

e. Docket No. RM07-3: Facilities Design, Connections and Maintenance Reliability Standards

In January of 2007, several comments were filed in response to the Commission’s October 20, 2006 NOPR, as amended November 27, 2006. NOPR comments were due January 3, 2007.

SPP has not acted in this rulemaking.


1Q 2007

f. Docket No. RM05-5: NAESB Modifications to WEQ Business Practices The Commission issued a NOPR in Docket No. RM05-5003 on February 20, 2007, to

amend its regulations under the Federal Power Act to incorporate a revised version of the Coordinate Interchange Standards adopted by the Wholesale Electric Quadrant (“WEQ”) of the North American Energy Standards Board (“NAESB”) on June 22, 2006, and filed with the Commission November 16, 2006.

g. Docket No. RM02-12: Remedying Undue Discrimination through Open Access

Transmission Service and Standard Electricity Market Design, etc. On February 23, 2007, ISO-NE filed proposed amendments to the ISO-NE OATT,

supplementing its October 27, 2006 Filing, pursuant to Order No. 2006-B.

SPP has not acted in this rulemaking. h. Docket No. RM06-10: New PURPA Section 210(m) Regulations Applicable to

Small Power Production and Cogeneration Facilities On October 20, 2006, the Commission issued Order No. 688, modifying the mandatory

power purchase obligation for electric utilities under the Public Utility Regulatory Policies Act of 1978 (“PURPA”) as mandated by the Energy Policy Act of 2005. The Commission declined to evaluate the SPP market, pending market redesign; finding, instead, that SPP would meet the criteria of PURPA section 210(m)(1)(A) once the market redesign becomes effective, and that SPP meets the 210(m)(1)(B)(i) criterion. SPP member electric utilities may rely on the Commission’s partial findings if filing to terminate the mandatory purchase obligation. However, SPP members must make all other required showings under section 210(m)(1)(B).

Several requests for rehearing or appeal and clarification of Order No. 688 were filed, and rehearing was granted on December 20, 2006. Commission action is forthcoming.

i. Docket No. RM06-12: Regulations for Filing Applications for Permits to Site Interstate Electric Transmission Corridors

On January 16, 2007, the Commission granted rehearing of Order No. 689, which was

issued November 16, 2006. Order No. 689 implemented new regulations in accordance with section 1221 of the Energy Policy Act of 2005 to establish filing requirements and procedures for entities seeking to construct electric transmission facilities.

SPP has not acted in this rulemaking.


1Q 2007

3. FERC Administrative Proceeding a. Docket No. AD06-9: RTO and ISO Seams Issues in the Eastern Interconnection A technical conference addressing RTO border utility issues was held March 29, 2007. Carl Monroe presented on behalf of SPP. 4. FERC ERO Rules and Organizational Filings

a. Docket No. RR06-1: NERC Filing of Version 5 Reliability Standards Development Procedure

SPP intervened in this proceeding on January 10, 2007, and on January 12, NERC

submitted a compliance filing pursuant to the Commission’s October 30, 2006 Order, which required certain modifications to section 1302 of NERC’s Rules of Procedures regarding the makeup of NERC committees and subgroups. NERC’s January 12 Filing was conditionally accepted by the Commission on March 9, 2007.

On January 18, 2007, the Commission issued an order accepting in part and rejecting in part NERC’s October 18, 2006 compliance filing.

SPP and the IRC requested clarification, or in the alternative rehearing, of the January 18 Order on February 20 and March 7, 2007, respectively. Rehearing of the January 18 Order was granted by the Commission on March 22, 2007.

b. Docket No. RR06-3: NERC Filing of the 2007 Business Plans and Budgets

A number of comments on NERC’s December 22, 2006 compliance filing were filed with the Commission, and on March 29, 2007, FERC issued a letter order accepting NERC’s compliance filing.

A technical conference was held on March 2, 2007 to explore whether the Western Electricity Coordinating Council’s (“WECC”) reliability coordinator activities should be funded through the ERO.

SPP is an intervenor in this docket. c. Regional Entity Delegation Agreements: Docket Nos. RR07-1, RR07-2, RR07-3,

RR07-4, RR07-5, RR07-6, RR07-7, RR07-8 These dockets involve delegation agreements between the following: (1) NERC and

Texas Regional Entity, a division of ERCOT; (2) NERC and the Midwest Reliability Organization; (3) NERC and Northeast Power Coordinating Council: Cross Border Regional


1Q 2007 Entity, Inc.; (4) NERC and Reliability First Corporation; (5) NERC and SERC Reliability Corporation; (6) SPP Regional Entity Delegation Agreement (“SPP-NERC RDA”); (7) NERC and Western Electricity Coordinating Council; and (8) NERC and Florida Reliability Coordinating Council.

SPP intervened in each docket on January 10, 2007.

5. FERC Electric Rate and Other Formal Filings of Interest a. Docket No. ER06-451: EIS Market implementation SPP made eight (8) filings the first quarter of 2007 concerning implementation of SPP’s real-time energy imbalance (“EIS”) market, which was met by the issuance of several orders. In particular, the Commission accepted SPP’s October 26, November 30, December 15, 2006 and January 25, 2007 compliance filings, but rejected SPP’s December 20, 2006 filing of revisions to Attachment AE. In a separate order, the Commission also directed SPP to either incorporate various demand response provisions into portions of SPP’s OATT relating to its real-time EIS Market or explain why such provisions should not be included. In this quarter, rehearing was granted of both the November 17, 2006 Order and the January 26, 2007 Order. Rehearing of the October 26, 2006 was denied, although clarification was provided. b. Docket No. ER06-729: Attachment M and Attachment AE Revisions On January 26, 2007, the Commission granted SPP’s limited request for rehearing of the October 19, 2006 Order, which conditionally approved SPP’s OATT revisions modifying the loss compensation provisions of Attachment M and Attachment AE to SPP’s OATT to reflect SPP’s proposed EIS Market. In its January 26 Order, the Commission also approved SPP’s November 20, 2006 compliance filing, made pursuant to the Commission’s October 19 Order. c. Docket Nos. ER03-765 and ER07-371: Reactive Compensation On January 31, 2007, SPP responded to all protests of its December 26, 2007 compliance filing, contending that provisions to pay generators within the defined deadband or pay lost opportunity costs are unnecessary; Schedule 2 will not provide SPP or the Balancing Authorities opportunity to favor the Balancing Authorities’ generation; SPP’s proposed qualified generator provisions are just and reasonable; and that Calpine’s claims are beyond the scope of this proceeding. On February 27, 2007, the Commission notified SPP that the December 26, 2006 Filing is deficient, requesting that SPP filed additional information with the Commission by March 29, 2007. SPP has complied with the Commission’s request.


1Q 2007

d. Docket No. ER07-603: Partially Executed Service Agreement between SPP and Golden Spread for Market Participants Selling into SPP’s EIS Market

On March 5, 2007, SPP submitted a partially executed service agreement for Market Participants selling into its real-time energy imbalance service markets with Golden Spread Electric Cooperative, Inc. (“Golden Spread”). An effective date of February 1, 2007 is requested. Commission action is forthcoming. e. Docket No. ER07-643: Executed Meter Agent Service Agreements between AEP and SPP EIS Market Participants On March 21, 2007, SPP filed eight (8) executed Meter Agent Services Agreements between AEP and various participants in SPP’s real-time EIS Market. An effective date of February 1, 2007 is requested.

f. Docket No. EL07-6: FERC Inquiry Regarding Gas-Electric Coordination Issues

On January 16, 2007, SPP filed its response to the Commission’s October 25, 2006 Order, requiring ISOs and RTOs to explain whether any changes were required to ensure effective coordination between the scheduling of electricity transmission and the scheduling practices associated with gas supply and capacity procurement. Comments on SPP’s January 16 Filing were submitted by WPS Resources Corporation and FPL Energy Generators.

g. Docket No. EL07-28: Xcel’s Complaint against SPP Regarding the Registration

of JD Wind Resource Units 1 through 4

On January 4, 2007, Xcel Energy Services, Inc. (“Xcel”) filed a complaint, on behalf of itself and Southwestern Public Service Company (“SPS”) concerning SPP’s registration of JD Wind Resources Units 1 through 4. Xcel requested that the Commission: (1) interpret SPP’s OATT and relevant business practices and find that SPP does not have the authority to unilaterally register assets to SPS without SPS’s consent and (2) direct SPP to remove the assets from the list of generation facilities for which SPS is registered in the SPP EIS Market, until such time as SPS agrees to register these facilities itself. The Commission issued an order March 22, 2007, granting Xcel’s complaint against SPP; finding that, “SPP does not meet the applicable SPP OATT definitions or registration requirements of a Market Participant and, therefore, SPP lacks authority pursuant to the SPP OATT to register generation facilities as resources for the imbalance market.”


1Q 2007 6. Addressing First Five Waiver Requests under Attachment J SPP has received five waiver requests. The following is a synopsis of these requests: Golden Spread Electric Cooperative (“GSEC”) filed a waiver for reservation 1034404 by letter on May 19, 2006. SPP asked for additional information by letter on August 9 and again on September 25, 2006. SPP made a recommendation to the MOPC and prior to the presentation to discuss the GSEC waiver request. GSEC pulled their waiver request, and the waiver request was not discussed. Oklahoma Gas and Electric (“OG&E”) filed a waiver for reservation 1032973 by letter on May 19, 2006. SPP asked for additional information by letter from OG&E, as was done for the GSEC waiver request. SPP made a recommendation to the MOPC. The MOPC asked the CAWG to review the recommendation because it was the first to move forward. At the same time the MOPC asked the BOD to allow additional time due to unusual circumstances. The CAWG reviewed the waiver in a special meeting on December 20, 2006 and recommended to the MOPC to grant the waiver for the addition of $747,000 of Base Plan funding. The MOPC made a recommendation to the Board of Directors to grant the waiver. The BOD approved the waiver in their January 2007 meeting contingent on the approval of the RSC. The RSC approved the waiver on March 1, 2007. Westar Energy (“Westar”) filed a waiver for reservation 1086655 by letter on October 13, 2006. SPP asked for additional information by letter from Westar in November of 2006. SPP reviewed the Westar waiver with the CAWG. The SPP recommended to the MOPC in a special meeting on January 26, 2007 to approve the waiver to be fully Base Plan funded. The BOD approved the waiver in their January 30, 2007 meeting. Arkansas Electric Cooperative Corporation (“AECC”) and the Oklahoma Municipal Power Authority (“OMPA”) requested waiver for reservations 1161209 and 1159596, respectively. SPP presented a recommendation to the CAWG to approve the waivers in the March 25, 2007 meeting. The CAWG is recommending to the RSC to approve the waivers in their upcoming April 24, 2007 meeting. During the teleconference with the RSC on April 5, 2007, issues were discussed and the discussion will be continued. SPP will be making a presentation to the MOPC April 11, 2007 to approve the waivers. The BOD meets April 24, 2007. Baring unusual circumstances, the BOD will take action on these waivers. 7. Approval of Entergy’s ICT Proposal Entergy’s ICT Proposal is addressed in FERC Docket Nos. ER04-699-000 and ER05-1065-000 (Docket No. ER05-1065 replaced Entergy’s Initial ICT Proposal in Docket No. ER04-699, which closed June 30, 2005), as well as Louisiana Public Service Commission Docket No. U-28155 and Arkansas Public Service Commission Docket No. 04-050-U. On January 16, 2007, Entergy submitted a compliance filing in Docket No. ER05-1065-006 pursuant to the Commission’s October 18, 2006 Order, which accepted in part and modified


1Q 2007 in part Entergy’s May 24, 2006 compliance filing to establish an ICT. The Louisiana Public Service Commission, Cottonwood and the TDU Intervenors filed protests to Entergy’s January 16 Compliance Filing. Entergy made two (2) filings this quarter relating to inaccurate data. Entergy cited OASIS software issues, advising the Commission that Entergy cannot fully construct certain AFC impact logs for the period of October 27, 2006 thru November 12, 2006. SPP filed its first Quarterly Performance Report as the ICT on March 9, 2007 in FERC Docket No. ER05-1065-000. 8. Arkansas Regulatory Proceedings

a. Docket Nos. 05-021-U, 06-142-U and 06-171-U SPP filed in support of a number of Certificate of Convenience and Necessity (“CCN”)

and Certificate of Environmental Capability and Public Need (“CECPN”) applications of member Transmission Owners before the Arkansas Public Service Commission (“APSC”).

A public hearing was held January 3, 2007, and on February 1, the APSC granted

Southwestern Electric Power Company’s (“SWEPCO”) application in Docket No. 05-021-U for a CECPN to construct, operate and maintain new 345 kV electric transmission line, approximately 11.25 miles in length, extending between SWEPCO’s existing Chambers Spring Substation and its existing Tontitown Substation. On March 14, 2007, the APSC granted SWEPCO a CCN in Docket No. 06-142-U to rebuild and convert the voltage of SWEPCO’s North Fayetteville 69 kV station in Washington County.

Arkansas Electric Cooperative Corporation filed a CECPN Application in Docket No. 06-171-U on December 21, 2006. A public hearing was held March 21, 2007, and on March 23, the APSC granted Arkansas Electric Cooperative Corporation a CECPN for the construction, ownership, operation and maintenance of a combustion turbine generating facility in Washington County near Elkins, Arkansas. On December 22, 2006, SWEPCO applied for a CCN in Docket No. 06-172-U to rebuild and convert its existing 69 kV transmission line in Washington County to 161 kV between SWEPCO’s Fayetteville and North Fayetteville substations. A hearing was held April 5, 2007.

b. Docket No. 06-028-R On January 4, 2007, the APSC approved Resource Planning Guidelines for Electric

Utilities. An additional order addressing whether to adopt the PURPA standard may be issued after completion of a study to determine whether Arkansas utilities are already using diverse fuel sources.


1Q 2007

c. Docket No. 07-009-U On March 8, 2007, the APSC approved SPP’s January 29, 2007 application for authority

to issue secured promissory notes in a principal amount not to exceed $5,400,000 with a maturity not to exceed twenty (20) years to U.S. Bank National Association.

9. Texas Regulatory Proceeding

a. Texas CREZ Rule: Project No. 31852

The Public Utility Commission of Texas (“PUCT”) adopted a final CREZ rule December 15, 2006, and SPP continues to be involved in the CREZ selection process.

On April 2, 2007, the elected representatives of the Texas Panhandle/South Plains filed comments with the Commission, expressing their support for transmission infrastructure improvements in SPP and encouraging the Commission to speed development of SPP’s “X Plan.”

b. Proceeding to Designate CREZS: Docket No. 33672 SPP was granted intervenor status in this proceeding on January 25, 2007 and filed an

Analysis of Transmission Alternatives for Competitive Renewable Energy Zones on January 26. A hearing is scheduled for June 11-15, 2007.

c. Entergy Gulf States, Inc.’s TTC Plan: Docket No. 33687

SPP moved to intervene in this proceeding on January 19, 2007, and was granted intervenor status on January 26. On February 20, 2007, PUCT Staff filed a motion for summary decision on Gulf States’ proposed Transition to Competition (“TTC”) Plan. Responses to Staff’s motion were due March 1, 2007. On March 30, 2007, SPP filed a statement under section 4 of the protective order, claiming exemption from disclosure of highly sensitive information. A technical conference followed on April 2-3, 2007, and on April 4, SPP filed confidential responses to ETC 1-2, 1-3, 1-5, 1-6, 1-7, 1-9, and 1-12. A combined ERCOT and SPP technical conference will be held April 11, 2007, with a hearing scheduled for May 21-25, 2007.


1Q 2007 10. SPP EHV Overlay Assessment Phase One of the Assessment is complete. This phase, which required development of assumptions based on stakeholder input, included a meeting at the TWG on February 7, 2007, at which the assumptions for the study were finalized. Phase Two, which involves development of futures and sensitivities from Phase One, is in progress, with completion of model development slated for Friday, April 13, 2007.


1Q 2007

LEGAL MATTERS PENDING

No Legal Matters Pending


1Q 2007

EXECUTIVE INDUSTRY ACTIVITIES

Executive Event

Nick Brown University of Arkansas Electrical Engineering College (Jan. 26) IRC/CEO Meeting, Dallas, TX (Jan. 31) Public Utility Commission of Texas, Austin, TX (Feb. 9) Gentile Firm Conference Keynote, Washington, D.C. (Mar. 6-7) Arkansas Public Service Commission (Mar. 13) IRC/CEO Meeting (Mar. 21) Public Utility Commission of Texas, Austin, TX (Mar. 22) Michael Desselle University of Arkansas Electrical Engineering College (Jan. 26) NERC Board of Trustees, Scottsdale, AZ (Feb. 13) 13th Annual FERC briefing, Washington, D.C. (Mar. 6-7) NERC Finance and Audit Committee Meeting, Chicago, IL (Mar. 12) Arkansas Public Service Commission (Mar. 13) NAESB, Houston, TX (Mar. 22) Les Dillahunty Arkansas Public Service Commission, Little Rock (Jan. 8) Public Utility Commission of Texas, Austin, TX (Feb. 6-7) Arkansas Public Service Commission (Mar. 13) Cleco RTO/ICT, Pineville, LA (Mar. 20) IRC/RLC, California (Mar. 22-23) Tom Dunn Arkansas Public Service Commission, Little Rock (Jan. 8) Prudential, Dallas, TX (Mar. 6) Arkansas Public Service Commission (Mar. 13) IRC/CFO Meeting, Baltimore, MD (Mar. 20-21) Carl Monroe IRC Markets Committee Meeting, Austin, TX (Feb 22-23) Arkansas Public Service Commission (Mar. 13) Pacific Northwest National Laboratories (Mar. 20) MAPP RTC Meeting (Mar. 27) FERC Eastern Seams Technical Conference, Washington, D.C. (Mar.

28-29) Stacy Duckett IRC/GC Meeting, Toronto, Canada (Feb. 25-26) Arkansas Public Service Commission (Mar. 13)


1Q 2007

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


1Q 2007

STAFFING REPORT

SPP Employee count as of January 1, 2007:

245

1Q New hires: 17 YTD Terminations:

0 – Retirees 5 – Voluntary terminations 0 – Involuntary terminations 1 – Interns (part time/seasonal)

6

SPP Employee count as of March 31, 2007

256

There are 295 full time employees in the 2007 budget.

1

SPP.org 1

Energy Efficiency & Demand Response

Simply check off the task, or…

take meaningful action.

2

SPP.org 3

The Commission’s Order

• In its September 26, 2006 Order on Rehearing in SPP’s EIS docket, the Commission stated: “Given the careful development and coordination involved in demand response implementation, we believe that further consideration is warranted to ensure that an efficient and reliable market is developed in the SPP footprint. SPP shall coordinate with utilities, state commissioners and other interested parties to consider provisions for participation of demand resources in the imbalance market.”

SPP.org 4

The Commission’s Order Cont.

• “Within six months of the date of the order (September 26, 2006), SPP shall file either (a) modifications to its tariff to incorporate procedures, for implementation in summer 2007, for the commitment in the day-ahead process and dispatch in the imbalance market of interruptible demand, behind the meter generation and other demand resources that are capable of providing imbalance service, or (b) an explanation and rationale for not including such provisions in its tariff and identify specific barriers, causes or issues that prevented the filing. At that time, the Commission will consider whether it would be useful to convene a technical conference to consider the filing.”

3

SPP.org 5

Compliance Deadline

• On March 20, 2007 SPP filed a request to extend the due date of the required compliance filing by six months.

• Compliance is now required on or before September 26, 2007.

SPP.org 6

More Transmission

Less Carbon

4

SPP.org 7

Actual & Forecast Peak Demand

38000

40000

42000

44000

46000

48000

50000

52000

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

(MW

)

2003 Forecast2004 Forecast2005 Forecast2006 ForecastActual

SPP.org 8

Actual & Forecast Capacity Margins

8

10

12

14

16

18

20

22

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

(%)

2003 Forecast2004 Forecast2005 Forecast2006 ForecastActual

5

SPP.org 9

Reserve Margin by Region (2007E v. 2003A)

Source: Cambridge Energy Research Associates

10© 2007 Electric Power Research Institute, Inc. All rights reserved.

• Growing scientific findings and public opinion that GHG emissions are contributing to climate change…

• Priority of 110th Congress …

• U.S. responsible for 1/4 of worldwide CO2 emissions…

• Electric utilities responsible for 1/3 of U.S. CO2 emissions…

• Agreement that technology solutions are needed…

…But What is Feasible???

Context

6

SPP.org 11

Increases in CO2 Emissions

Source: Department of Energy

SPP.org 12

Sources of GHG Emissions by Sectors (Tons)2

Source: US Environmental Protection Agency, 2004

7


• At the request of its Board of Directors, EPRI was asked to estimate the technical potential for CO2 emissions reductions from the U.S. electricity sector.

• EPRI developed 7 technology deployment targets and estimated the CO2reductions that could result between now and 2030. Economic modeling of these targets is currently being conducted.

• Conclusions:– The technical potential exists for the U.S. electricity sector to significantly

reduce its CO2 emissions over the coming decades.– No one technology will be a silver bullet – a portfolio of technologies will

be needed.– Much of the needed technology isn’t available yet – substantial R&D,

demonstration is required.

Approach


0

500

1000

1500

2000

2500

3000

3500

1990 1995 2000 2005 2010 2015 2020 2025 2030

U.S

. Ele

ctric

Sec

tor

CO

2 Em

issi

ons

(mill

ion

met

ric to

ns)

U.S. Electricity Sector CO2 Emissions

• Base case from EIA “Annual Energy Outlook 2007”– includes some efficiency, new renewables, new nuclear– assumes no CO2 capture or storage due to high costs

Using EPRI deployment assumptions, calculate change in CO2 relative to EIA base case

8


0

500

1000

1500

2000

2500

3000

3500

1990 1995 2000 2005 2010 2015 2020 2025 2030

U.S

. Ele

ctric

Sec

tor

CO

2 Em

issi

ons

(mill

ion

met

ric to

ns)

EIA Base Case 2007

CO2 Reductions … Technical Potential*

150 GWe Plant Upgrades46% New Plant Efficiency

by 2020; 49% in 2030

No Existing Plant Upgrades40% New Plant Efficiency

by 2020–2030Advanced Coal Generation

5% of Base Load in 2030< 0.1% of Base Load in 2030DER

10% of New Vehicle Sales by 2017; +2%/yr Thereafter NonePHEV

Widely Deployed After 2020NoneCCS

64 GWe by 203012.5 GWe by 2030Nuclear Generation

70 GWe by 203030 GWe by 2030Renewables

Load Growth ~ +1.1%/yrLoad Growth ~ +1.5%/yrEfficiency

TargetEIA 2007 ReferenceTechnology

* Achieving all targets is very aggressive, but potentially feasible.


Key Technology Challenges

1. Smart grids and communications infrastructures to enable end-use efficiency and demand response, distributed generation, and PHEVs.

2. A grid infrastructure with the capacity and reliability to operate with 20-30% intermittent renewables in specific regions.

3. Significant expansion of nuclear energy enabled by continued safe and economic operation of existing nuclear fleet; and a viable strategy for managing spent fuel.

4. Commercial-scale coal-based generation units operating with 90+% CO2 capture and storage in a variety of geologies.

The U.S. electricity sector will need ALL of the following technology advancements to significantly reduce CO2 emissions over the coming decades:

9

SPP.org 17

SPP.org 18

10

SPP.org 19

SPP.org 20

• Simply check off the task, or…

take meaningful action?

1

Markets & OperationsPolicy Committee

• John Olsen –Chair• Bill Dowling – Vice Chair

www.spp.org 3

Something to think about:

There must be bands of enthusiasts for everything on earth---fanatics who shared a vocabulary, a batch of technical skills and equipment, and, perhaps, a vision of some single slice of the beauty and mystery of things, of their complexity, fascination, and unexpectedness.

~Annie Dillard

www.spp.org 4

Overview

• Action Items - Tariff• Sections 19.4 and 32.4 – Letters of Credit• Section 28.4 – Secondary Service• Market PRRs – 124, 140 and 143• Waivers – AECC and OMPA

• Informational Items• Ice Storm – January 2007• Future Market Steps• SPP Criteria Review• Criteria Waivers

www.spp.org 5

Action Items

www.spp.org 6

Letter of Credit Requirements• Sections 19.4 and 32.4 require the Transmission

Customer to supply a LOC or Cash to cover the cost of any transmission upgrades

1.Doesn’t matter if Base Plan Funded or Direct Assigned2.LOC required before construction begins3.For large upgrades, can have a negative impact.

• Finance Committee passed three recommendations to the RTWG

1.Allow bilateral negotiations between the TC and TO2.Allow the TC & TO to have other forms of Securities

besides Cash and LOC3.Allow the Staging of LOC amount to be based upon the

costs incurred by the TO

2

www.spp.org 7

RTWG Analysis• White Paper Concerns– In Background Materials

1.RTWG could not support the “Bilateral” negotiations2.Would require each TO to create credit rules (Attachment L of Order 890).3.Impractical with aggregate study process4.Could create comparability problems

• What is Impact of Default on other Customers?• Only has negative impacts on other Transmission

Customers if the defaulting customer has Direct assigned costs

• If Costs are Base Plan funded, no one takes on additional costs as long as the load remains.

www.spp.org 8

RTWG Proposal• RTWG passed the following four recommendations:

1.Modify 19.4 & 32.4 to only require LOCs for TCs that receive Direct Assigned Costs

2.Limit LOC to only those costs that are assigned to the TC3.Reinsert the pro-forma language to allow SPP to accept other types of Credit besides LOC and Cash at SPP’s option

4.Allow the staging of the LOC based upon the expected costs of the project less the revenue paid by the TC

• RTWG passed the tariff language• 11 for, 0 against, 2 abstentions

www.spp.org 9

Status• Credit Task Force reviewed the RTWG proposal

• Several members still wanted the bilateral agreement option between a TC and a TO

• Voted to accept RTWG’s Proposals 1, 2 and 4 unanimously• Voted 66% for and 34% against RTWG Proposal 3

• MOPC approved RTWG proposal subject to Finance Committee endorsement without substantive changes

• Finance Committee reviewed and concurred

www.spp.org 10

Recommendation

• MOPC recommends that the BOD accepts the proposed tariff language changes to Sections 19.4 and 32.4

• MOPC approve unanimously

www.spp.org 11

Network Secondary Service

www.spp.org 12

Background Information

• October 5, 2006, the Market Monitoring Unit (MMU) presented initial findings to the Business Practice Working Group (BPWG) concerning the use of secondary Network Integration Transmission Service (NITS).

• MMU found no evidence of deliberate abuse, but there is potential.

3

www.spp.org 13

MMU Background Information

33%

31%

Transmission unused

27%17%February 2007

33%17% September 2006

Maximum Hourly usage

Secondary NITS used

• Suggested a tariff change that could use approx 15,000 MWh of un-utilized transmission capacity.

• MMU believes this introduces a use it or can’t have immediate access to it (lose it) type of rule to Non-firm Secondary NITS.

www.spp.org 14

Proposed Tariff Changes

• Limit the amount of Secondary Network Service to:1.200 MW or 125% of the NITS Customer’s average maximum usage on four separate days

2.Shall not exceed 110% of the NITS customer’s peak load

• Tariff language proposed based on recommendation of SPP’s FERC attorney

• RTWG approved unanimously vote

www.spp.org 15

Recommendation

• MOPC recommends that the BOD accepts the proposed tariff language changes to Section 28.4

• MOPC approve unanimously

www.spp.org 16

Summary of Waiver Requests – 1/31/2007 –SPP-2006-AG3-AFS-2 (Turk Power Plant)

$ 8,841,737$ 16,915,218SPP-2006-AG3-AFS-3 Assigned Costs

3/2/07 - 3/13/073/2/07 - 3/13/07Additional Data Requested/Response

$ 7,380,000$ 12,600,000Base plan funding maximum

1159596 – 41 MW1161209 – 70 MWTransmission Service Request

OMPAAECC

www.spp.org 17

Benefit Analysis

• Capacity needed to meet anticipated load growth• Fuel diversity for project participants• SWEPCO CCN filings represent the Turk Power Plant

option as the better of four evaluated options including two pulverized coal options and two IGCC (integrated gasification combined cycle) options.

• Unit is dispatchable• Full load heat rate – 8,992 BTU/kWh• Not near a non-attainment area• SWEPCO projects an 87.6 % unit availability• Life of plant commitment

www.spp.org 18

Waiver Request Discussion

• Attachment J Section III.C.2.ii allows all or part of the excess above the Safe Harbor Limit to be classified as Base Plan funded when the new or changed DR exceeds the five-year commitment.• OMPA reservation 1159596 is a 20 year reservation• AECC reservation 1161209 is a 20 year reservation.• Both AECC and OMPA are committed to the life of the

Turk Power Plant as noted in their letters to SPP dated March 13, 2007.

4

www.spp.org 19

CAWG Waiver Request Discussion

• CAWG discussed the AECC and OMPA Waivers• CAWG proposed in their March 28, 2007 regular meeting

consideration of $180,000/MW Safe Harbor Limit funds for the total group of Turk participants.

• 618 MW x $180,000/MW = $ 111,240,000• SPP-2006-AG3-AFS-2 required upgrades equal to $

116,423,188.• SPP-2006-AG3-AFS-3 due to be posted April 11, 2007, the

Turk upgrade costs unknown at this time.

• CAWG Recommendation• The CAWG is recommending that the SPP RSC

recommend to the SPP Board of Directors to grant the waiver request from AECC and OMPA.

www.spp.org 20

Waiver Recommendations – AECC & OMPA• SPP Staff Recommendation for AECC & OMPA Waivers

• SPP Staff does not agree with the contemplated CAWG Aggregate Study Base Plan funding analysis; 1. Since project participant response factors may cause different

upgrades. 2. This method is not consistent with Attachment Z Section V; Cost

Allocation for Requested Upgrades • Waiver amount is not final, additional Aggregate Facility Study

required.• Turk Generation Interconnection studies are in progress, with

Interconnection Agreement will be the next step.• SPP recommends the Base Plan funding be increased

to 100% of the required E&C cost associated with the addition of the Turk DRs for AECC and OMPA.

www.spp.org 21

Recommendation

• MOPC recommends that the BOD approves the waivers requested by AECC and OMPA

• MOPC approved with one no vote - KCPL

www.spp.org 22

Tariff Changes for PRR 124

• Current – MMU required to post daily the “annual hours of constraint” by flowgate.

• Proposed – MMU to post “annual hours of constraint” by Resource.

• This is the actual data used by the SPP Offer Cap system to calculate Offer Caps for each pivotal Resource.

www.spp.org 23


• Current – Final settlement statement issued at 45 days after operating day. Resettlements 1-11 each occur 30 days in succession after the final settlement.

• Proposed - Modify language to move final settlement statement to 47 days after the operating day.

• Example - Resettlement 1 would still be issued 30 days after the final, but would now occur on day 77 instead of day 75.

www.spp.org 24


• Present – All market flow is assigned to Firm transmission priority up to the Firm flow limit

• Proposed – Only Scheduled market flow is assigned to Firm transmission priority. Other unscheduled market flow is at a lower priority.

5

www.spp.org 25

Recommendation

• MOPC recommends that the BOD accepts the proposed tariff language changes to implement PRR 124, 140, and 143

• MWG and RTWG approved unanimously• ORWG reviewed and no reliability issues

were identified• MOPC approve unanimously

www.spp.org 26

Information Items

www.spp.org 27 www.spp.org 28


6



www.spp.org 35

Impacts

• So how many customers lost power?• At peak of storm/event on Sunday, the 14th, approximately 300,000

customers in the SPP regional area were in the dark – with the longest outages up to 15 consecutive days (customer equipment involved);Polled utilities were AEP, CU, EDE, GRDA, KAMO, OG&E and WFEC

• So what did all of this cost?

• Estimated to be $150-$175 million in Arkansas, Oklahoma, and Missouri • Over 1200 miles of transmission circuit miles affected. Several hundred

miles of distribution line.• Over 4000 distribution and transmission poles• Restoration on-going and will take months• Tree trimming costs and efforts were excessive and not ideal.

www.spp.org 36

Future Market Discussion

• MWG has extended meetings from 2 to 3 days for a day to discuss Future Market Design

• Developed an outline of the high level Ancillary Service Market design • To be distributed at the June SPC Retreat

• MWG’s meeting in May will be a review of all other RTO/ISO Ancillary Service Markets

7

www.spp.org 37

Vision for Enforceable StandardsNERC

ReliabilityStandards

RegionA B

C

D

E F

G NERCReliabilityStandards

Regional Reliability Standards

BA C E HD F G

H

Regional Criteria and Procedures

Today

SPP Criteria

Future

SPP Criteria

www.spp.org 38

SPP Criteria (Relationship with NERC standards)

FIB Standards

Review for Enforceability** Under Review

Criteria 2.0, 8.0,10.0,11.0,…

Criteria 6.1, 6.2, 6.4,7.1, 7.3, 7.4

Criteria 1.0, 3.0, 4.0,5.2, 7.2, 7.3, 7.4,

7.5, 9, 12,…

EnforceableStandards*

Continent-Wide Standards*

??

Regional Standards

??

Membership Agreement/Contracts*

www.spp.org 39

Other MOPC Work

• Accepted two waivers of SPP Criteria• Westar Special Protection Scheme for Jeffery Energy

Center• Xcel Energy for Underfrequency Load Shedding

pending completion of installations

Carl A. Monroe

[email protected]

1

www.spp.org 1

SPP BOD and Members Committee meetingApril 24

Oklahoma City, OK

Unintended Consequences Analysis

www.spp.org 2

Prior Analysis Findings

At the February 2007 CAWG and RTWG meetings, Staff presented MW-MI allocations for 2006-2008 Base Plan projects in the approved STEP

No unintended consequences were identified with the potential exception of one project in NW AR

Staff and AEP questioned results associated with Fayetteville 69 to 161 kV Conversion Project assuming that the impact of the treatment of losses in the solutions may be skewing MW-MI allocations

2

www.spp.org 3

Supplemental Analyses

Investigate impact of alternative techniques to address impacts of shifts in system losses on MW-MI allocations

Past studies assumed area slack bus output would be adjusted for any change in losses which can have an adverse impact on area MW-MI and neighboring area MW-MI depending upon the location of area slack buses

www.spp.org 4

Sensitivity Analyses Performed

For the Fayetteville Conversion Project, Staff investigated the following four methods to account for a shift in losses in the MW-MI Allocations:

• Lossless DC – System considered lossless. No generators are adjusted to count for losses

• Participation – adjust output of all generators in control area based on Pmax on a pro-rata basis to account for any shift in area losses

• System Swing – TVA Brown’s Ferry generator would adjust output to account for any change in losses across entire grid

• Area Slack – designated generator in each Control Area adjusts output to account for any change in area losses

3

www.spp.org 5

ConclusionsMISO LODF approach does not consider the impact of losses on MW-MI allocations, but a 1% minimum LODF cut-off is also incorporated at MISO

Base Plan Projects impacts on area losses are not insignificant in many circumstances, therefore Lossless DC is not appropriate

Final MW-MI allocations need to remove possible influence due to changes in losses resulting from a shift in area slack bus due to change in area losses which can be material for many projects

Final MW-MI allocations should be based on system participation for all generators within a Control Area, not a single slack bus in each area or the system swing bus in the solution

No tariff changes are necessary at this time. The change in the manner losses are handled can be implemented without changes to the SPPOATT

www.spp.org 6

Southwest Power Pool, Inc. MARKETS AND OPERATIONS POLICY COMMITTEE

Recommendation to the Board of Directors April 24, 2007

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

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

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

The following stakeholders participated in group discussions:

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

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

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

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

Tariff Modifications – Sections 19.4 & 32.4 Facilities Study Procedures

Letter of Credit Issues

Background and Analysis The background and analysis associated with the proposed changes to Tariff Sections 19.4 and 32.4 are set out in the attached white paper from Dennis Reed (Westar Energy).

At its meeting on March 29, 2007, the RTWG approved modifications to Tariff Sections 19.4 and 32.4 by a vote of 11 in favor and 2 abstentions.

Recommendation The RTWG recommends that the MOPC approve the modifications to Tariff Sections 19.4 and 32.4.

Approved: Regional Tariff Working Group March 29, 2007 Markets and Operations Policy Committee April 11, 2007

Action Requested: Approval of the proposed modifications to Tariff Sections 19.4 and 32.4.

Attachments: The recommended Tariff change language is attached with the related white paper.

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Recommendation to the RTWG Suggested Changes to Sections 19.4 and 32.4 of the SPP OATT

March 26, 2007 Dennis Reed

Background: Several years ago when we included the new credit policy (Attachment X) in the SPP OATT, sections 19.4 and 32.4 were also modified to limit the types of security that a transmission customer must post when upgrades to the transmission system are needed to grant its transmission service request. Specifically, the language now states:

“. . . The Transmission Customer shall provide the Transmission Provider with a letter of credit in the form specified in Appendix C to Attachment X, Credit Policy or Cash Deposit equivalent to the costs of new facilities or upgrades. . . .”

The original language in the OATT allowed the customer and SPP to negotiate other forms of credit besides a Letter of Credit (LOC) or cash, but that language was removed at the suggestion of SPP staff. Staff was concerned that a customer might use up his unsecured credit with SPP covering transmission upgrades and not have any credit left to cover the EIS imbalance costs. Also the language does not differentiate between the different ways a transmission upgrade may be paid for. Therefore, a customer that has a transmission request with needed upgrades must always put up an LOC or cash for any upgrades allocated to a customer regardless of whether or not the customer qualified for Base Plan Funded (BPF) or not. Over the past year, several customers have had to put up large LOCs, even though the projects were BPF or otherwise rolled into rates. Most transmission customers cannot carry large amounts of LOCs over an extended period of time. Requiring an LOC or cash for all projects will eventually restrict the amount of transmission being built. The Finance Committee’s recommendation is to allow a Transmission Customer to directly negotiate credit terms with the building TO in the hope that other forms of security acceptable to the building TO could be arranged between the TC and the TO. Analysis: In reviewing this proposal three reoccurring thoughts keep coming to mind:

1) Can we make this practice “comparable” for all customers under the SPP OATT? 2) Can we make the suggestion practical? 3) Are we really addressing the underlying issue?

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Issue 1: Comparability My concern about comparability comes from the fact that SPP is the Transmission Provider under the tariff and has rules to treat all customers in an equal manner. It is very likely that each TO would have different credit requirements from the other TO’s in the SPP. This could cause a customer to be treated differently in one zone as compared to another zone. A TO could easily come under attack for preferential treatment of certain customers over others unless they create, and file at FERC, credit policies similar to those under the SPP OATT. Issue 2: Practicality The proposal would probably create an administrative nightmare for the TO to establish a Transmission credit department that would have to administer such tariff provisions and track all the multiple customers the aggregate study assigned the upgrade to. Also the TO would have to do all of this within the limited time frame of the SPP tariff so that the TC’s could return their service agreements to the SPP on schedule. From the TC’s point of view, now instead of working with just the SPP, they would need to meet and negotiate credit terms with every TO building upgrades for their request(s). In most instances, this could easily be up to three or more owners. A customer’s ability to arrange all the credit requirements within a short timeframe would probably be difficult at best. Issue 3: Are we fixing the correct problem? The original purpose of having a TC post an LOC or other security for upgrades originates back to the pro-forma tariff. In that world, transmission requests were done sequentially and usually involved requests for point-to-point transmission service. The costs for upgrades needed to grant that service were directly assigned to the customer under an “OR” pricing methodology. SPP would look at the revenue stream over the life of the transmission service request and charge the customer the higher of the transmission rate or the total cost of the upgrades. Money to cover the costs of the upgrades were sent to the building TO(s) to off set increases in its revenue requirements so the transmission rates paid by the customers in the building zone were not affected. The LOC was the guarantee that the revenue stream would exist pursuant to the customer’s contract. The LOC was a mechanism to protect the TC’s in the building zone, not the TO. The TO would have recovered its cost by shifting the costs to all the other customers if the revenue stream stopped prior to the cost of the upgrade being fully paid for. The way the SPP OATT works today, it is a more complicated world. Certainly the point-to-point requests still exist as describe above, and some sort of credit arrangement needs to continue for those situations. The issue I see is that the current tariff does not address what happens when an upgrade is “rolled” into the OATT charges. This can happen if the upgrade is required for reliability reasons, TO criteria or if the customer qualifies for BPF. If the upgrade is rolled into the OATT charges, all the customers in the building zone, and perhaps across the SPP, receive a pro-rata share of the costs. Therefore the question

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now is: What happens to the rates paid by the other customers in the SPP if the customer that required the upgrade goes bankrupt, or fails to complete the full term of the transmission agreement? I believe in this case the answer is “nothing”. If the customer is an LSE serving a load in the SPP footprint, the LSE may go bankrupt, but the load remains. Since the load is stable, the costs allocated to all customers remain the same. The TOs are not impacted (they get their approved Revenue Requirements) and the TCs are not impacted since their rates do not change. Proposal:

1) To modify Sections 19.4 and 32.4 to only require transmission customers to have an LOC or other credit instrument if the costs of the upgrades are directly assigned to them.

2) To limit the LOC to the only the cost of the upgrade allocated to the customer through the aggregate study process.

3) To reinsert the pro-forma language back into Sections 19.4 and 32.4 allowing SPP to negotiate other forms of credit acceptable to it.

4) If an LOC is required, allow SPP to increase and decrease the LOC amount for each customer based upon the expected expenditures or remaining revenue stream.

Proposal one still requires cash or an LOC if an upgrade is directly assigned to a customer. This still follows the intent of the pro-forma tariff and protects the TO.s and TC.s from a customer default. It also removes the requirement of a customer to post an LOC for upgrades that are BPF since the LOC is not needed to protect either the TO or the TCs. Proposal two makes it clear that if a TC is directly assigned only a portion of the upgrade costs, the LOC is only required for those costs directly assigned to it. So if a customer is directly assigned 10% of a $1,000,000 upgrade, it only has to post an LOC of $100,000. Proposal three needs to be discussed with SPP staff, however, the reinsertion of the pro-forma language allows SPP the option to approve other types of credit instruments proposed by the customer at the discretion of the SPP. Proposal four will better define a practice that SPP already does for larger projects or projects that are not required for several years. As an example, if a direct assigned upgrade will not be started for 3 years, then an LOC is not required until the start of the quarter in the year that the expenditures are to begin. If the upgrade were to take more than one year to complete, then the LOC would only be for the accumulated cost and projected cost of the year until the project is completed. Once the project is completed and put into service, the amount of the LOC would then be reduced each year by the amount of the amortized cost of the project over the remainder of the service request.

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The sum of these four proposals meets the general goal of the Finance Committee’s concern regarding the need of a customer to post a LOC. Allow SPP to have consistent rules in regards to each TC credit. Give additional flexibility back to the SPP (and the Finance Committee) to investigate different methods of crediting that can be used by all TCs. And finally to minimize the amount of the LOC a TC needs to post by allowing SPP to adjust the amount annually.

RTWG Approved Modification 03-29-07

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19.4 Facilities Study Procedures:

a) If a System Impact Study indicates that additions or upgrades to the Transmission System are needed to supply the Eligible Customer's service request, the Transmission Provider, within thirty (30) days of the completion of the System Impact Study, shall tender to the Eligible Customer a Facilities Study Agreement pursuant to which the Eligible Customer shall agree to reimburse the Transmission Provider and any affected Transmission Owner(s) for performing the required Facilities Study. For a service request to remain a Completed Application, the Eligible Customer shall execute the Facilities Study Agreement and return it to the Transmission Provider within fifteen (15) days. If the Eligible Customer elects not to execute the Facilities Study Agreement, its Application shall be deemed withdrawn and its Financial Security, pursuant to Section 17.3, shall be returned with interest, if any. Upon receipt of an executed Facilities Study Agreement, the Transmission Provider in coordination with the appropriate Transmission Owner(s) will use due diligence to complete the required Facilities Study within a sixty (60) day period. If the Transmission Provider together with the affected Transmission Owner(s) are unable to complete the Facilities Study in the allotted time period, the Transmission Provider shall notify the Transmission Customer and provide an estimate of the time needed to reach a final determination along with an explanation of the reasons that additional time is required to complete the study.

b) When completed, the Facilities Study will include a good faith estimate of (i) the cost of Direct Assignment Facilities to be charged to the Transmission Customer, (ii) the Transmission Customer's appropriate share of the cost of any required Network Upgrades as determined pursuant to the provisions of Part II of the Tariff, and (iii) the time required to complete such construction and initiate the requested service.

c) The Transmission Customer shall provide the Transmission Provider with a letter of credit in the form specified in Appendix C to Attachment X, Credit Policy, or Cash Deposit, or other form of security acceptable to the Transmission Provider equivalent to only those the costs of new facilities or upgrades that are directly assigned to the customer for cost recovery. Within the time set out in Attachment P, the Transmission Customer shall execute a Service Agreement or request the filing of an unexecuted Service Agreement and provide the required letter of credit or Cash Depositsecurity or the request will no longer be a Completed Application and shall be deemed terminated and withdrawn.

d) If a letter of credit is required, the Transmission Customer must post the letter of credit for the full amount of the upgrade cost assigned to it. The Transmission Provider may, at its sole discretion, waive the posting of the letter of credit until the beginning of the quarter when costs for the upgrade are first incurred. The amount of the letter of credit shall increase each year there after based upon the total amount of money expended, plus an estimate of the amount of money that is going to be expended in the next 12 months.


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The amount of the letter of credit shall be reduced each year by the amount of revenue paid by the Transmission Customer related to the direct assigned cost of the upgrade from the previous year.

32.4 Facilities Study Procedures:

a) If a System Impact Study indicates that additions or upgrades to the Transmission System are needed to supply the Eligible Customer's service request, the Transmission Provider, within thirty (30) days of the completion of the System Impact Study, shall tender to the Eligible Customer a Facilities Study Agreement pursuant to which the Eligible Customer shall agree to reimburse the Transmission Provider and any affected Transmission Owner(s) for performing the required Facilities Study. For a service request to remain a Completed Application, the Eligible Customer shall execute the Facilities Study Agreement and return it to the Transmission Provider within fifteen (15) days. If the Eligible Customer elects not to execute the Facilities Study Agreement, its Application shall be deemed withdrawn and its Financial Security shall be returned with interest, if any. Upon receipt of an executed Facilities Study Agreement, the Transmission Provider in coordination with the affected Transmission Owner(s) will use due diligence to complete the required Facilities Study within a sixty (60) day period. If the Transmission Provider together with the affected Transmission Owner(s) are unable to complete the Facilities Study in the allotted time period, the Transmission Provider shall notify the Eligible Customer and provide an estimate of the time needed to reach a final determination along with an explanation of the reasons that additional time is required to complete the study.

b) When completed, the Facilities Study will include a good faith estimate of (i) the cost of Direct Assignment Facilities to be charged to the Eligible Customer, (ii) the Eligible Customer's appropriate share of the cost of any required Network Upgrades, and (iii) the time required to complete such construction and initiate the requested service.

c) The Eligible Customer shall provide the Transmission Provider with a letter of credit in the form specified in Attachment C to Attachment X, Credit Policy, or Cash Deposit or other reasonable form of security acceptable to the Transmission Provider equivalent to only those the costs of new facilities or upgrades that are directly assigned to the customer for cost recovery. The Eligible Customer shall have thirty (30) days to execute a Service Agreement or request the filing of an unexecuted Service Agreement and provide the required letter of credit or Cash Depositsecurity or the request no longer will be a Completed Application and shall be deemed terminated and withdrawn.

d) If a letter of credit is required, the Transmission Customer must post the letter of credit for the full amount of the upgrade cost assigned to it. The Transmission Provider may, at its sole discretion, waive the posting of the letter of credit until the beginning of the quarter when costs for the upgrade are first incurred. The amount of the letter of credit shall increase each year there after based upon the total amount of money expended, plus an estimate of the amount of money that is going to be expended on the upgrade in the


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next 12 months. The amount of the letter of credit shall be reduced each year by the amount of revenue paid by the Transmission Customer related to the direct assigned cost of the upgrade from the previous year.

Southwest Power Pool, Inc. MARKETS & OPERATIONS POLICY COMMITTEE










Tariff Modifications – Section 28.4 Secondary Service

Background The SPP Internal Market Monitor noted that substantial amounts of non-firm secondary transmission service have been reserved by Network Service customers that remained unused. The Internal Market Monitor approached the Business Practices Working Group (BPWG) with their findings and a suggestion that the BPWG develop a business practice that specifies appropriate constraints on the reservation of secondary non-firm network transmission service.

Analysis The Business Practices Working Group provided a business practice that specified certain limitations on Network customers’ ability to reserve secondary non-firm service, predicated on 110% of peak load, secondary non-firm service actually used historically and other relevant parameters.

During the Regional Tariff Working Group’s discussion of this proposed business practice, the question arose concerning the need to specify such limitations as a Tariff provision, rather than in a business practice. SPP’s FERC counsel advised that such provisions should be made part of the Tariff. Revised Tariff language specifying these limitations was developed. The process associated with administration of the exception specified in the last sentence of the proposed addition to this Tariff section is set out in Business Practice 2.11.

At its meeting on March 29, 2007, the RTWG unanimously approved modifications to Tariff Section 28.4 that added these limitation provisions.

Recommendation The RTWG recommends that the MOPC approve the modifications to Tariff Section 28.4.

Approved: Regional Tariff Working Group March 29, 2007 Markets & Operations Policy Committee April 11, 2007

2

Action Requested: Approval of the proposed modifications to Tariff Section 28.4.

Attachments: The recommended Tariff change language is attached.

3

RTWG Approved Modification – March 29, 2007

28.4 Secondary Service: The Network Customer may use the Transmission System

to deliver energy to its Network Loads from resources that have not been designated as

Network Resources. Such energy shall be transmitted, on an as-available basis, with no

additional charges imposed under Schedules 7, 8, 9, or 11. Deliveries from resources

other than Network Resources will have a higher priority than any Non-Firm Point-To-

Point Transmission Service under Part II of the Tariff or any non-firm point-to-point

service under any other transmission tariff or agreement where the service is being

provided by a Transmission Owner. A Network Customer seeking to utilize such

secondary service to deliver energy to its Network Load must submit a request on the

Transmission Provider’s OASIS for each transaction. For any single hour scheduling

period of time, a Network Customer’s total reserved capacity for secondary service shall

not exceed the greater of (i) 200 MW or (ii) 125 percent times the Network Customer’s

average of the highest hourly non-firm network schedules from four (4) separate days for

the previous twelve (12) calendar month period or (iii) 25% of the Network Customer's

peak Network Load from the prior calendar year; provided, however, that the reserved

capacity for such secondary service shall not exceed 110 percent of the Network

Customer’s peak Network Load from the prior calendar year. For the first twelve (12)

calendar months that a new Network Customer is receiving Network Integration

Transmission Service, the new Network Customer’s reserved capacity for secondary

service shall not exceed 110 percent of its peak Network Load from the prior calendar

year. If requested by the Network Customer, the Transmission Provider shall determine

on a non-discriminatory basis whether an exception to the limits to secondary service set

forth in this Section shall be granted.

Southwest Power Pool, Inc. MARKETS AND OPERATIONS POLICY COMMITTEE

Recommendation to the Board of Directors On Attachment J Waiver Requests

April 24, 2007

Organizational Roster The following members represent the Southwest Power Pool Les Dillahunty, Vice President, Regulatory Policy Pat Bourne, Director, Transmission Policy Jay Caspary, Director, Engineering John Mills, Manager, Tariff Studies

Background Attachment J of the SPP Tariff addresses recovery of costs associated with new transmission facilities. Subsection III of this section addresses Base Plan funding for network upgrades, including Safe Harbor Cost Limit of $ 180,000/MW, and provides for waivers, whereby application may be made for additional Base Plan funding for a network upgrade in excess of the Safe Harbor Limit based on three independent factors. On January 31, SPP received a request for waiver under Attachment J of the SPP Tariff for costs in excess of the Safe Harbor Cost Limit for Base plan funding from Arkansas Electric Cooperative Corporation (AECC) and from Oklahoma Municipal Power Authority (OMPA) for new Designated Resources of 70 and 41 MW respectively, based on the upgrade costs associated with transmission from the Turk Power Plant. SPP’s 120-day deadline under Attachment J is May 31, 2007. The next regularly scheduled Board of Directors meeting is April 24, 2007. Analysis AECC and OMPA requested a waiver based upon Section III.C.2.ii of Attachment J for a reservation of 20 years. The 20 year reservations and the commitment to the life of the Turk Power Plant justify full Base Plan funding for the required upgrades to facilitate the transmission for AECC and OMPA new Designated Resource. Both waiver requests have been discussed in the February and the March meetings of the CAWG. Based on the discussion held in these meetings, the CAWG is recommending that the SPP RSC recommend to the SPP Board of Directors to grant the waiver requests for AECC and OMPA. The RTWG held a brief discussion of the AECC and OMPA waiver requests at their March meeting but took no action. Recommendation The recommendation of SPP Staff is to provide waivers of such extent that the projects required for the AECC and OMPA new designated resources are fully Base Plan funded. Approved: Markets & Operations Policy Committee April 11, 2007 One No Vote – KCPL Action Requested: Approval of AECC and OMPA waiver requests Attachments: Waivers requests and response letters

415 North McKinley, #140 Plaza West Little Rock, AR 72205-3020 (501)-614-3356 Fax: (501) 666-0376 March 2, 2007 Mr. Ricky Bittle Vice President; Planning, Rates & Dispatching Arkansas Electric Cooperative Corporation 1 Cooperative Way Little Rock, AR 72219-4308 Subject: Request for Waiver under OASIS reservation # 1161209 Dear Mr. Bittle: The request for a full or partial waiver submitted by AECC is based on a twenty year term of service. In order to facilitate our evaluation of this waiver request, SPP requests AECC’s cooperation in working through this process by providing an explanation of the factors used by AECC in determining the length of transmission service request, including a detailed explanation as to why those factors should quality the project for full Base Plan funding. Please also provide documentation substantiating the 20 year ownership based on the reservation request. Please provide a detailed explanation of the importing Designated Resources that are being used currently that may be temporarily or permanently undesignated due to the addition of the Turk 70 MW new Designated Resource. SPP has now posted SPP-2006-AG3-AFS-2. Based on this revised posting for the remaining Customers in the study queue, please provide SPP an explanation of the regional benefit analysis AECC used to determine that full Base Plan funding will benefit the SPP region and how these interconnections will provide reliability and the opportunity for additional competition within the SPP footprint. To assist SPP in constructing the overall case regarding the waiver request, SPP requests information on the projected fuel mix of AECC in the year prior to this unit’s operation as compared to the fuel mix during the first full year after commercial operation. Robert Shields made a presentation to the Cost Allocation Working Group (CAWG) on February 21, 2007, addressing this waiver request. During that discussion, plant owners

Lighting the Past…Powering the future

referenced the additional costs, not included in the waiver request, incurred by AECC and others associated with the interconnection of the unit to the grid. While that information may not be influential in terms of the waiver request, we believe that information to be relevant and would like to capture those points for the record that will accompany SPP’s recommendation on the waiver request. Please provide the above requested data no later than March 16th to allow SPP to review the data provided and to formulate a report to the CAWG/RTWG for recommendation to the MOPC in accordance with the tariff requirements. Thank you. Sincerely,

John E. Mills, P.E. Manager, Tariff Studies Southwest Power Pool cc: Gary Voigt Les Dillahunty Pat Bourne Jay Caspary


415 North McKinley, #140 Plaza West Little Rock, AR 72205-3020 (501)-614-3356 Fax: (501) 666-0376 March 2, 2007 Mr. Robin J. Morecroft PE Director of Engineering Services Oklahoma Municipal power Authority 2300 East Second St. Edmond, OK 73083-1960 Subject: Request for Waiver under OASIS reservation # 1159596 Dear Mr. Morecroft: The request for full or partial waiver submitted by OMPA is based on a twenty year term of service. In order to facilitate our evaluation of this waiver request, SPP requests OMPA’s an explanation of the factors used by OMPA in determining the length of transmission service , including a detailed explanation as to why those factors should quality the project for full Base Plan funding. Please also provide documentation for the 35 year ownership noted in your letter. Please provide a detailed explanation of how this “very long term transmission reservation, will facilitate SPP’s ability to efficiently plan the system for the region’s long term needs and will result in significant savings to SPP”. SPP has now posted SPP-2006-AG3-AFS-2. Based on this revised posting for the remaining Customers in the study queue, please provide an explanation of the regional benefit analysis OMPA has used to determine that full Base Plan funding will benefit the SPP region and how these interconnections will provide regional value for peaking or intermittent generation, and how this will accomplish lower costs to other ratepayers. To assist SPP in constructing the overcall case regarding this waiver request, SPP requests information on the projected fuel mix of OMPA in the year prior to this units operation as compared to the fuel mix during the first full year after commercial operation. Gene Anderson made a presentation to the Cost Allocation Working Group (CAWG) on February 21, 2007, addressing this waiver request. During that discussion, Gene


referenced the additional costs incurred by OMPA associated with the interconnection of the unit to the grid which were not included in the waiver request. While that information may not be influential in terms of the waiver request, we believe that information to be relevant and would like to capture those points for the record that will accompany SPP’s recommendation on the waiver request. Please provide the above requested data no later than March 16th to allow SPP to review the data provided and to formulate a report to the CAWG/RTWG for recommendation to the MOPC in accordance with the tariff requirements. Thank you. Sincerely,

John E. Mills, P.E. Manager, Tariff Studies Southwest Power Pool cc: C. Holman T. Littleton H. Dawson Les Dillahunty Pat Bourne Jay Caspary


Southwest Power Pool, Inc. MARKETS & OPERATIONS POLICY COMMITTEE










Protocol Revision Requests 124, 140, 143

Background The SPP Market Working Group (MWG) approved PRRs 124, 140 and 143 and provided draft modifications to Tariff Attachments AE and AF to reflect the effect of those protocol changes.

Analysis At its meeting on March 30, 2007, the RTWG approved the modifications to Tariff Attachments AE and AF designed to reflect the provisions of PRRs 124, 140 and 143 with minor modifications to the proposed language of Attachment AE Section 4.3 (b) as advanced by the MWG. Tariff modifications related to all three PRRs were unanimously approved.

Recommendation The RTWG recommends that the MOPC approve the modifications to Tariff Attachments AE and AF. The recommended Tariff change language is set out at the end of each of the PRR Recommendation Reports provided by the MWG.

Approved: Regional Tariff Working Group March 30, 2007 Markets & Operations Policy Committee April 11, 2007

Action Requested: Approval of the proposed modifications to Tariff Attachments AE and AF.

Attachments: The recommended Tariff change language is set out at the end of each of the PRR Recommendation Reports provided by the MWG.

2

PRR Recommendation Report

PRR124_Recommendation_Report Page 1 of 3

PRR Number 124 PRR

Title Posing Hours of Constraint

Timeline (Normal or Urgent)

Normal Recommended Action Approve

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

Section 14.4, A.2.4.3 Annual Hours of Constraint

Revision Description

Current protocols require SPP Market Monitors to post daily the “annual hours of constraint” by flowgate. Proposed revision would be to post “annual hours of constraint” by Resource, the actual data used by the SPP Offer Cap system to calculate Offer Caps for each pivotal Resource.

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

Unanimously approved in the February 16, 2007 MWG conference call.

RTWG Review

ORWG Review

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

Original Sponsor Name Alan McQueen Company Southwest Power Pool

Comments Received Comment Author Comment Description



Proposed Protocol Language Revision

Market Power Mitigation

14.4.1 Economic Withholding B.A. Energy Market Power

A.2.4.3. Annual Hours of Constraint The annual hours of constraint will be calculated individually for each Resource subject to an Offer Cap and will be the sum of 12 months of actual hours of constraint in the EIS Market for constrained flowgates affecting the Resource. In the event that multiple constraints simultaneously affect a Resource, coincident hours of constraint will be only be counted as one hour for the Offer Cap calculation for such a Resource. During the first year of operation of the EIS Market, the hours of duration for TLR Level 3 and above events for each flowgate shall be used as a proxy for hours of constraint in the EIS Market. For each flowgate, this proxy shall apply for the period prior to the start of the EIS Market that is included in the 12 month rolling sum calculation of annual hours of constraint. The annual hours of constraint will be updated daily for inclusion in the daily calculation of the Offer Cap on each Resource and will be posted electronically by SPP for each flowgate Resource on the www.SPP.org website.

Tariff change:

3.2.4 (Section C) Attachment AF

The annual hours of constraint will be calculated individually for each affected Resource under Section 3.2.2 of a Market Participant and will be based on the most recent 365 days (366 days for a leap year) of total hours of constraint in the EIS Market for constrained flowgates affecting each Resource. In the event that multiple constraints simultaneously affect a Resource, overlapping hours of constraint will be eliminated from the Offer Cap calculation for such a Resource. During the first year of operation of the EIS Market, the hours of duration for TLR Level 3 and above events for each flowgate shall be used as a proxy for hours of constraint in the EIS Market that are included in the calculation of annual hours of constraint. The annual hours of constraint

Formatted: Bullets and Numbering

http://www.spp.org/



will be updated daily for inclusion in the daily calculation of the Offer Cap on each affected resource and will be posted electronically by the Transmission Provider for each flowgateResource.



PRR Number 140 PRR

Title Final and Resettlement Statement Timeline


Urgent Recommended Action Approve


Amend Section 11.6.2, 11.6.3 and 11.6.4

Revision Description

Modify language to move final settlement statement from 45 days after the operating day to 47 days after the operating day. The existing resettlements 1-11 each occur 30 days in succession after the final settlement. As an example, resettlement 1 would still be issued 30 days after the final, but would now occur on day 77 instead of day 75.



RTWG Review

ORWG Review


Original Sponsor Name SDMSTF Company





11.6.2 Final Settlement Statements SPP will use settlement data to produce the final statements for each Market Participant for the given Operating Day. Final statements will be created at the end of the forty-seventh (47th) calendar day following the Operating Day. If the forty-seventh (47th) day is not a Business Day, the final statement is issued on the next Business Day thereafter. statements will be issued at the end of the first business day following the forty-forth (44th) calendar day following the Operating Day. The final statement will reflect changes to settlement charges generated on the Operating Day’s initial Settlement Statement.

11.6.3 Resettlement Statements A resettlement statement will be produced using corrected settlement data due to resolution of disputes, or correction of data errors. Resettlements occurring prior to the production of the final settlement statement will be included in the final settlement statement. Resettlement statements 1 through 11 will be created at the end of the following calendar days following the Operating Day. If the calendar day is not a Business Day, the respective resettlement statement is issued on the next Business Day thereafter. Resettlement 1 77 days after operating day Resettlement 2 107 days after operating day Resettlement 3 137 days after operating day Resettlement 4 167 days after operating day Resettlement 5 197 days after operating day Resettlement 6 227 days after operating day Resettlement 7 257 days after operating day Resettlement 8 287 days after operating day Resettlement 9 317 days after operating day Resettlement 10 347 days after operating day Resettlement 11 377 days after operating day Any settlement and billing dispute of initial statements resolved in accordance with Dispute Resolution process of the Tariff will be corrected on the final statement for the Operating Day. In



the event that the final statement does not resolve a dispute from an initial statement for a given Operating Day, SPP will resolve the dispute on a Resettlement Statement for that Operating Day. Only Disputes for which the RTO is notified by the end of the time period for Dispute Notification will be considered for Resettlement.

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

Settlements Timeline



ISS-Initial Settlement Statement FSS-Final Settlement Statement

Tariff Language: Section 6.1 (b) of Attachment AE: (b) The Transmission Provider shall issue a final settlement statement for an Operating Day no later than 44 47 Calendar Days following the applicable Operating Day unless the 44th 47th Calendar Day following the applicable Operating Day is not a Business Day, in which case, the final settlement statement shall be issued on the first Business Day thereafter.

Sunday Monday Tuesday Wednesday Thursday Friday Saturday

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

ISS Day 1

ISS Day 2

ISS Day 3

ISS Day 4

ISS Day 5

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

ISS Day 6 ISS Day 7 ISS Day 8

ISS Day 9

ISS Day 10

ISS Day 11

ISS Day 12

Time Lapse for Day 21 to Day 48

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

ISS Day 41 ISS Day 42 ISS Day 43 FSS Day 1 FSS Day 2 FSS Day 3

ISS Day 44 FSS Day 4




PRR Impact Analysis Report

PRR Number 140 PRR

Title Final Settlement Timeline

Impact Analysis Date April 3, 2007

Cost/Budgetary Impact $2,000

Estimated Project Time Requirements *unless otherwise indicated, project time requirements begin upon project initiation

SPP Staffing Impacts (across all areas) None

SPP Computer System Impacts

SPP Settlements System - Update the Approval Control table within the SPP Settlements System to allow for creation of Settlement Statements at the end of the seventh calendar day.

SPP Business Function Impacts

Extending the timeline for initial settlement to seven days affords the opportunity to obtain the missing or corrected meter data needed to produce more accurate settlement statements.

Alternatives for an Efficient Implementation (include explanation of impacts) None

Evaluation of Interim Solutions (e.g., manual workarounds)

Comments

PRR140 Final Settlement Timeline Impact Analysis Page 1 of 1



PRR Number 143 PRR

Title Market Flow Changes




Section 6.7.1, 6.7.2 and 6.7.3

Revision Description Correct the “changing the usage of the limit” to be taken to the JOA/CMP for discussion based on feedback from MWG participants.



RTWG Review

ORWG Review


Original Sponsor Name Lanny Nickell Company Southwest Power Pool





6.7.1 Market Flow

As required by the Congestion Management Process (CMP) prescribed by the SPP-MISO Joint Operating Agreement, SPP will determine and submit to the NERC IDC its Market Flows on all SPP Coordinated Flowgates (CFs) and Reciprocal Coordinated Flowgates (RCFs). SPP’s CFs are those flowgates identified as being impacted by activities within SPP. SPP’s RCFs are those flowgates identified as being impacted by activities within SPP and one or more entities operating under the requirements similar to those of the CMP. Currently those entities include SPP, MISO, MAPP, TVA, and PJM.

SPP’s Market Flows represent impacts from one or more of the following components:

1) Native Load Schedules from both Market and Self-dispatched Resources

2) Tagged intra-Balancing Authority schedules from both Market and Self-dispatched Resources

3) Tagged schedules where the source is a market Resource or Load Settlement Location and the sink is a Load Settlement Location

4) Any unscheduled output from Units generation resources offered into the EIS Market and dispatched by SPP in accordance with these Protocols (hereinafter referred to as “EIS impact.”)

In accordance with the CMP, Firm Flow Limits are derived for CFs while both Firm and Non-firm Network limits are derived for RCFs. For CFs, SPP will establish a Firm Flow Limit equal to the sum of firm transmission reservations and Gen-to-Load impacts. For RCFs, SPP will establish a Firm Flow Limit based upon the allocation of Flowgate Capacity determined pursuant to the reciprocal coordination process. On both CFs and RCFs and in accordance with the CMP, SPP will assign Firm (F-7) curtailment priorities to those its Market Flows Firm (F-7)that are scheduled (i.e., categories 1-3 from the above list) using firm transmission service, up to the applicable Firm Flow Limit. On CFs, any remaining Market Flows will be assigned and Non-firm Network (NN-6) curtailment priorities. On RCFs and in accordance with the CMP, SPP will assign Non-firm Network (NN-6) curtailment priorities to those Market Flows that are scheduled using transmission service having a priority greater than Non-firm Hourly and any remaining Market Flow that is unscheduled, up to the Non-Firm Network Limit. On RCFs, any Market Flow in excess of the Non-firm Network Limit will be prioritized as Non-firm Hourly (NH-2)its Market Flows Firm (F-7), Non-firm Network (NN-6), and Non-firm Hourly (NH-2) curtailment priorities. Through this process, Firm limits are derived for CFs while both Firm and Non-firm Network limits are derived for RCFs. See the following example for an illustration of how real-time Market Flow might be assigned on a RCF over a 24-hour period.



Example of SPP Market Flow Assignment on a RCF

At least every 15 minutes, SPP will send Market Flow values for all CFs and RCFs to the IDC in the appropriate priority levels for the current hour and next hour. During a TLR event, the IDC will use this information to prescribe appropriate reductions in Market Flows and curtailments of tags whose impacts are not reflected in Market Flows. SPP systems will identify Market Flows that must be curtailed to achieve any obligation assigned by the IDC by binding of the constraint in the security constrained economic dispatch system.

SPP will determine the amount of Market Flows associated with EIS impacts by subtracting scheduled Market Flows from total mMarket flowsFlows. For CFs, any EIS impacts that cannot be allocated to the Firm priority will beare considered to have Non-firm Network priority. For RCFs, any EIS impacts that cannot be allocated to Firm and the Non-firm Network priorities priority will be considered to have Non-firm Hourly priority.

During a TLR, EIS impacts greater than zero in a particular priority will be removed before curtailing any existing schedules in the same priority. Since the current SPP Market Structure provides no mechanism to directly assign the cost associated with relieving congestion to the schedules impacting a particular constrained flow gate, the CAT, in conjunction with curtailments from the IDC, shall curtail/adjust schedules to achieve a relieving impact equal to the Market Flow relief obligation assigned by the IDC. The result of such curtailment procedure will be that flows resulting from the EIS market dispatch will not provide counter flows to support schedule flows that are to be curtailed as described earlier.

0

50

100

150

200

250

300

350

400

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Legend

Market FlowsF-7

NN-6

NH-2

Scheduled F-7

Scheduled NN-6

Scheduled NM-5

Scheduled NW-4

Scheduled ND-3

EIS

Scheduled NH-2

EIS

F-7Limits

NN-6



6.7.2 NERC IDC Curtailments

The NERC IDC will receive all tagged transactions involving SPP. Under SPP Market Operations, the NERC IDC will be responsible during TLR events for prescribing curtailment of certain types of tagged transactions and prescribing Market Flow relief that SPP must achieve internally through its Market Operations. The NERC IDC will be responsible for prescribing curtailment of only those tags involving SPP for which impacts are not included in SPP’s Market Flows (see section 6.7.1). These include tags for schedules with external parties that are sourced or sunk in the SPP Market and tags for Interchange Transactions from Self-Dispatched Resources. Those tags for which impacts are included in SPP’s Market Flows will not be explicitly curtailed by the IDC. As stated in section 6.7.1, included in SPP’s Market Flows are impacts of tagged schedules where the source is a Resource or Load Settlement Location and the sink is a Load Settlement Location. In order for the IDC to distinguish those tags, MOS will communicate a market flag for each such Resource to the IDC each hour based on information in the Resource Plan. At least every 15 minutes, SPP will also send to the IDC the Balancing Authority(ies) wherein the marginal unit(s) reside. This information will be used by the IDC to calculate Transaction Distribution Factors (TDFs) for those schedules with external parties that source or sink in the SPP Market. This is reflected in the IDC as the SWPP_EXP marginal zone. If a unitgeneration resource in the SPP Market footprint is self-dispatched and has tagged schedules with external parties, the IDC will use unitresource level granularity in determining the TDF impact on flowgates.

6.7.3 SPP CAT Curtailments/Adjustments

CAT will be used to compute curtailments/adjustments of those schedules for which impacts are included in Market Flows. These include the following types of schedules:

1) Native Load Schedules from both Market and Self-dispatched Resources

2) Tagged intra-Balancing Authority schedules from both Market and Self-dispatched Resources

3) Tagged schedules where the source is a market Resource or Load Settlement Location and the sink is a Load Settlement Location

Any curtailments or adjustments made by CAT would be based on the Market Flow relief responsibility determined by the IDC.



SPP CAT will first determine if the net EIS component of the Market Flows at the priority directed to be curtailed by the IDC is sufficient to achieve the required Market Flow relief. If so, then no schedule curtailments or adjustments through SPP CAT will be necessary. If the EIS portion is insufficient to achieve the required Market Flow relief, CAT will curtail and/or adjust schedules, beginning with lowest priority, after considering the removal of the EIS portion of Market Flow.

The SPP CAT will communicate any curtailments/adjustments to RTO_SS. If any Self-Dispatched Resources identified in NLS are required to be curtailed, SPP CAT will also send the aggregate curtailment responsibility to each Resource owner for its curtailed Resources. Generator Shift Factors (GSF’s) will also be provided through a viewer to the Market Participants. These may be used by the Market Participants to determine how to best modify their Self-Dispatch Resource schedules while still maintaining the total level of reduction required. As warranted, the SPP CAT will also receive from the IDC the re-load amounts for Market Flows as a flowgate starts to become unconstrained. SPP CAT will use this information to re-load any curtailed or adjusted schedules.

Tariff Language Change:

Attachment AE

Section 4.3

4.3 The Transmission Provider shall use the following process to coordinate the operations of the Energy Imbalance Market during times when a TLR event is declared to manage congestion on one or more flowgates:. (a) The Transmission Provider shall identify schedules in the NERC IDC that are also included in Market Flows. (b) The Transmission Provider shall submit the Market Flow impact on each Coordinated Flowgate and Reciprocal Coordinated Flowgate to the NERC IDC. The Market Flow impact on each flowgate shall include the aggregate MW flow impacts of the following schedules on the identified flowgate: i. Energy Schedules relating to native load for which no tag - has been identified; ii, Energy Schedules entirely within a Balancing Authority Area for which a tag has been identified and where the source is either a Dispatchable Resource or Self-Dispatched Resource; and iii. Energy Schedules between Balancing Authority Areas for which a tag has been identified where the source is a Dispatchable Resource or Load Settlement Location and the sink is a Load Settlement Location. iv. Any unscheduled output from generation resources offered into the EIS Market and dispatched by SPP in accordance with these Protocols (hereinafter referred to as “EIS impact.”)



4.3 (d) The Market Flow contribution associated with Energy Imbalance Service shall be determined by the Transmission Provider by subtracting the scheduled Market Flow associated with the Energy Schedules defined in Section 4,3 (b) within that priority level defined in Section 4.3 (c) from the total calculated Market Flow for that priority. For Coordinated Flowgates, any Market Flow contribution of Energy Imbalance Service in excess of that assigned to the Firm priority shall be assigned a will be assigned Non-FinnFirm Network Prioritypriority. For Reciprocal Coordinated Flowgates, any Market Flow contribution of the Energy Imbalance Service in excess of amounts assigned to Firm or Non- Firm Network priorities shall be assigned a Non-Firm Hourly priority.

Southwest Power Pool, Inc. REPRESENTATIVES OF MWG, ORWG, RTWG

Recommendation to the MOPC April 23, 2007

External Generator Tariff Filing (PRR137)

Organizational Roster The following persons of the MWG, ORWG, and RTWG participated:

Gene Anderson, OMPA Gary Clear, OG&E Terri Eaton, Xcel Energy Jason Atwood, Redbud Energy Charles Locke, KCPL Rick McCord, EDE John Childs proxy for Tambra Offield, ETEC Tom Saitta, Aquila Tom Stuchlik, Westar Richard Dillon, SPP Grant Wilkerson, Westar

Bary Warren, EDE Charles Locke, KCPL Gary Newell, Lafayette Pat Bourne, SPP Bernard Liu, SPS Mark Foreman, Tenaska Steve Massey, Westar Alan Klassen, Westar Lanny Nickell, SPP Dan Boezio, AEP

Background See Attachment

Analysis See Attachment

Recommendation The consensus of this group is to recommend that the MOPC accept PRR137 with the attached changes and:

1) Direct RTWG to work with SPP staff to prepare the tariff language incorporating PRR137, including the attached changes, for a May 2 Compliance Filing with the Federal Energy Regulatory Commission,

2) Direct the MWG to modify PRR137 for the attached changes,

3) Direct the ORWG to address the Criteria items in the attached changes.

4) Direct the BPWG to address Business Practice items in the attached changes.

Approved: Members of the MWG, ORWG, RTWG April 20, 2007

Consensus

Action Requested: Approve Recommendation

Page 2 of 21

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Southwest Power Pool, Inc.

MARKET WORKING GROUP

OPERATING RELIABILITY WORKING GROUP

REGIONAL TARIFF WORKING GROUP

Proposed Changes to External Generator Market Design (PRR 137)

April 20, 2007

Proposal

The energy market will implement external generator participation in the real-time energy market as discussed in Protocol Revision Request 137 (PRR137) and include the following modifications and clarifications to PRR137 and applicable documents:

1) Market Participants (MP) with external generators will register a sink Settlement Location within an SPP energy market Balancing Authority (BA). This sink Settlement Location will be used in the evaluation of Transmission Reservation requests. This sink Settlement Location will not have any energy market settlement charges.

2) Point-to-point Transmission Service within SPP must be utilized to schedule to a sink Settlement Location registered by the MP with external generation.

3) The Tariff will specifically exclude Non-firm Transmission Reservations for external generators from incurring Transmission Reservation Service charges.

4) Available Transmission Capability (ATC) is appropriately reduced, pursuant to Criteria 4, for those Transmission Reservations made to facilitate external generator participation in the energy market. In SPP’s determination of these impacts, consideration will be given to historical usage of transmission service, thereby utilizing the lower of historical usage or the Transmission Reservation as per Criteria 4.

5) SPP Business Practices regarding the definition of competing requests for purposes of exercising preemption rules would be changed to define requests for Transmission Service to the same POD as competing. This allows for a higher priority Transmission Request to preempt a lower priority Transmission Request when there is insufficient ATC to accept both Requests for Transmission Service with similar impacts on flowgates.

6) SPP Criteria modifications will be requested, if determined necessary, to allow the request for assistance upon the loss of a non-firm schedule.

7) SPP will calculate the aggregate impact of the external generators on each BA NSI and include this information in updates to the BA.

8) The BA settlement agreement addresses recovery for a BA receiving penalties or sanctions resulting from SPP’s actions or inactions.

Background

The Federal Energy Regulatory Commission (FERC) ordered SPP to file within two months of the energy market implementation the Tariff language necessary to permit participation in the energy market by external generation. FERC has granted an extension of the filing date to May 2, 2007. PRR137 was approved by the Market Working Group (MWG) in February 2007 and rejected by the Operating Reliability Working Group

Page 3 of 21

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(ORWG) in March 2007. In the meantime, the Regional Tariff Working Group (RTWG) crafted language based on PRR137 for inclusion in the SPP Tariff.

Resulting from the questions raised, and action taken, by the ORWG and further discussion of the MWG, the Market and Operating Policy Committee (MOPC) discussed concerns with the design proposed in PRR137 for participation by external generators in the real-time energy market. The MOPC directed the MWG, ORWG, and RTWG to meet, discuss the issues identified during the MOPC meeting (Attachment A), and report to the MOPC on April 23. The MOPC discussion also acknowledge the Compliance Filing deadline of May 2 for the Tariff modifications related to external generator participation in the real-time energy market.

The MWG, ORWG, and RTWG met in Tulsa, Oklahoma on April 16 to discuss resolution of the concerns and preparation of filing materials.

Analysis

The April 16 meeting of the MWG, ORWG, and RTWG identified a list of requirements to be addressed in PRR137 changes (Attachment B) and discussed possible solutions to each item. The primary concerns can be grouped into the categories of (1) Barriers to participation, either financial or operational, (2) Impact upon Transmission Owners and Participants within the SPP geographic region, (3) Impact on Balancing Authority (BA) operations. The discussion identified a preference to establish SPP as both a BA and a sink for these types of transactions. After a brief review of actions necessary (waiver from the North American Electric Reliability Council – NERC, identification of the responsibilities assumed by SPP, construction of computer systems and personnel necessary to support the identified responsibilities, etc.) and an discussion that the establishment of SPP as a BA would likely delay external generator participation, the meeting participants agreed to move forward with this interim solution that would be re-evaluated to determine improvements in the market design in the following situations: (i) in connection with the establishment of SPP as a BA, as part of a more comprehensive discussion focused on the BA initiative, and/or (ii) if any external generator or other Market Participant requests improvements based on the good faith belief that the tariff provisions adopted to implement PRR 137 are not producing the intended result of allowing the integration of external generation on a non-discriminatory basis.

Identified as barriers to participation were Transmission Reservation charges and the ability of Load Serving Entities (LSE) Market Participants to unduly reject transaction requests (Tags) using the Transmission Reservations. In order to mitigate the Transmission Reservation charges, the meeting participants discussed filing in the Tariff or discounting 100% the charges to an amount of zero. The ultimate decision was that the Tariff would specify that external generators with non-firm Transmission Service would not be charged for the Transmission Service. This practice extends only to the Transmission Service under the SPP OATT. Although the use of discounting, rather than Tariff language, was discussed, the higher assurance through the Tariff language was preferred. The concern about unjustified rejection of Tags by LSEs was discussed and the resolutions included Tariff language that restricts an LSE from rejecting a Tag and establishment of SPP as a sink Settlement Location. The use of SPP as a sink Settlement Location would include approval by NERC and is discussed in the prior paragraph. The discussion of using restrictive Tariff language disclosed that rejection of a Tag for valid reasons would also be restricted. Therefore, the suggested solution is to have the Market Participant with external generation register a Settlement Location within one or more BA(s) to which they wish to arrange a Transmission Reservation. This Settlement Location would, for Transmission Reservation evaluation purposes, be identified to the same set of busses as the other BA load. For settlement purposes, the Settlement Location will be included in the statement for the Market Participant that registered the location. No charges from the energy market will be incurred for this sink Settlement Location. The Market Participant registering the Settlement Location will also register a TSIN entry in the NERC registry reflecting themselves as the Purchasing/Selling Entity (PSE). Under Tagging procedures, the BAs (Sink and Source BAs) have approval and rejection rights and PSEs on the Tag have rejection rights. Since the PSE is the Market Participant with external generation, the LSEs will not have rejection rights to the Tags.

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The SPP Market Monitoring Unit will review all rejected Tags as requested by the Transmission Customer. If the MMU determines that such Tag was rejected for reasons other than as permitted by NERC standards, the MMU will refer the matter to FERC for appropriate action.

Impact on Transmission Owners (TOs) and LSEs included the lack of revenue for TOs from Transmission Reservation service and the utilization of ATC preventing LSEs from making arrangements to serve their load. After discussion of revenue and the utilization of NITS, the external generator using non-firm Transmission Service will not be charged for the service. Due to the special circumstances of certain Transmission Owners (e.g. Aquila), those paths were discussed as potentially being excluded from the discount. The potential hoarding of Transmission Reservations was discussed and decided that the SPP Market Monitor would be responsible for the monitoring for this type of activity. The concern regarding the utilization of ATC was also considered during the discussion resolving into two possible solutions: (1) Grant the reservation regardless of ATC and the Transmission Provider may deny the Tag in near real-time, (2) Allow the sale of additional non-firm Reservations based on evaluation of the actual historical usage of all non-firm Transmission Reservations. Solution 2 has the impact of expanding the potential for TLR from the over-subscription of Transmission Reservations beyond just the impact of external generator Reservations, but that impact is within reason and consistent with Criteria 4 requirements. Due to the potential “unduly discriminatory” impact of solution 1 and the extent of system changes to effect the solution, solution 2 is considered most viable. Transmission Customers should be aware that there is a potential for the non-firm TLR events. Criteria 4 section 4.5.5.3 discusses the use of historical scheduling against reservations for the calculation of Daily and Weekly ATC calculations. As an example in the calculation of ATC, if only 20% of the Transmission Reservations had been scheduled against across a specific flowgate, then the other 80% would be included as ATC. The BPWG has included discussion of usage of non-firm reservations versus scheduling has been across the entire SPP footprint about 20%. This should not be considered a guarantee of impacts on ATC.

Impact on BA activities were focused primarily on the ability to identify the impacts on Net Scheduled Interchange (NSI), ability to request reserve assistance, financial impacts from fines or deployment of reserves, and impact on Control Performance Standard (CPS) measurement. SPP will calculate the aggregate impact of the external generators on each BA NSI and include this information in updates to the BA. The Criteria language may require modifications to expand the ability to utilize reserves for the loss of a non-firm transaction and SPP will review the Criteria for these changes. The BA settlement agreement addresses recovery for a BA receiving penalties or sanctions because of SPP’s actions or inactions. The BA agreement in Section 7 deals with, and will address, costs on the sink BA resulting from the implementation of the EIS Market, including the impact of external generator activities. The deployment of reserves is already addressed in the FERC order regarding Reserve Sharing activities. The system design will include specific attention to any consequences on CPS.

Cross Reference

MOPC ISSUES MEETING REQUIREMENTS RESOLUTION SHORT DESCRIPTION

1 - schedule approval 4 – LSE unjustified rejection MP for external generator registers

sink location within an SPP BA.

Rejection of a Tag subject to Market Monitor review and action

2 – physical vs. contracted path Treatment is no different than for any other schedule injection

3 – SPP as a sink 3 – ATC impacts External generator provisions will be reevaluated for improvements:

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4 – LSE unjustified rejection (i) in connection with implementing SPP as a BA/sink; and/or (ii) good faith assertion that these provisions are not producing the intended result. ATC calculations will incorporate Criteria 4 requirements.

4 – potential fines 9 – impact on CPS BA agreement with SPP is considering cost recovery. Design is evaluated for impact on CPS.

5 – DC Tie impacts At this time, the ability to support and understand DC tie impacts will result in this being a future enhancement.

6 – loss responsibility Treatment is no different than for any other schedule injection.

7 – transmission priority 1 – transmission charges

3 – ATC impacts

Transmission may be arranged. Point-to-point non-firm to a sink of an SPP OATT NITS BA has a transmission charge of zero and ATC is calculated in accordance with Criteria 4 requirements.

8 – financial impacts on BA/LSE 4 – LSE rejection of Tag

8 – reserve charges

9 – impact on CPS

See MOPC item 1 and 4. The Tariff already directs recovery of reserve charges.

9 – Transmission Service Charges 1 – transmission charges

2 – transmission costs

See MOPC item 7. Additionally, the zero charge paths exclude certain paths.

10 – ATC impacts 3 – ATC impact See MOPC item 7.

11 – import limitations 9 – CPS violations Discussed as potentially self-limiting due to Transmission Reservation requirements. Will be reassessed as part of CPS concerns.

12 – “temporary” solution 4 – LSE rejection of Tag

6 – Sink BA visibility

9 – CPS violations

External generator provisions will be reevaluated for improvements: (i) in connection with implementing SPP as a BA/sink; and/or (ii) good faith assertion that these provisions are not producing the intended result.

Page 6 of 21

Attachment A

Page 1 of 8

MOPC Motion: Direct the RTWG, ORWG, and MWG to have a meeting to work through PRR 137 protocols, tariff revisions, and outstanding issues next week to provide recommendations for a MOPC conference call on Monday April 23rd at 4PM to review and further discussion in advance of next BOD meeting. Motion passed with 4 abstentions Issues:

1. Ensure that the default sink LSE within a BA is the BA’s affiliated LSE

1.1. Obligation or not on a BA to serve as the Sink for an External Resource (SOLUTION: Add a new paragraph (g) to Section 2.2.2 which states that: (a) a Balancing Authority may not refuse to accept a schedule provided by an External Resource unless the Balancing Authority determines (and the Transmission Provider confirms) that accepting the schedule would have a material adverse effect on the reliability of transmission operations; (b) if a Balancing Authority refuses to accept a schedule from an External Resource for any other reason (or engages in undue delay in determining whether it will accept or reject a schedule), the matter will be referred to the SPP Market Monitoring Unit; and (c) if the MMU finds that the Balancing Authority rejected the schedule without justification, it will refer the matter to FERC.)

1.2. Obligation or not that a MP associated with a BA allow its sink to be utilized (SOLUTION: Same as for item 1.1?)

2. Physical versus contractual path and associated CAT and IDC impacts

3. Waiver that would permit SPP to designate the “SPP EIS Market” as a valid sink for scheduling and transaction tagging purposes.

4. NERC, FERC potential fines for CPS1 and CPS2 violations

5. DC Tie operational impacts

6. Responsibility for losses

7. Need for and priority of transmission service within the Market Footprint

8. Financial settlements on LSEs and BAs

9. Whether or not Transmission Service Charges apply to any SPP transmission reservation that must be represented within the SPP region to facilitate the External Resource. (SOLUTION: Add a sentence to the end of Section 2.2.2(f) which states that External Resources will not be charged for transmission service within the SPP EIS Market Footprint to implement a Dynamic Dispatchable Schedule for the purpose of participating in the EIS Market.)

Page 7 of 21

Attachment A

Page 2 of 8

10. Whether or not Transmission ATC is reserved on the system in association with the preceding item particularly if charges are not to be applied.

11. Limitations if any:

11.1. Volume of External resources limited by the Operating Reserves? (SOLUTION: Add a sentence to Section 4.2 stating that a Dynamic Dispatchable Schedule submitted by an External Resource will be curtailed immediately if the SPP Reliability Coordinator determines that an IROL violation would otherwise result. Restoration of the schedule would be subject to any “deadband” on the IROL violation threshold that is adopted for Reserve Sharing Events.)

11.2. DC Ties?

11.3. Whether or not the External BA must agree to maintain schedule upon unit contingency of the external resource.

12. Do the tariff provisions to be considered at this time establish the “end state” solution for External Resources, or only a temporary solution pending further development?

Page 8 of 21

Attachment B

Page 1 of 8

Must Haves:

1. Free Transmission or equal footing with internal generation o Fully discount the Transmission Reservation rates to SPP NITS POD o File in tariff that sinks to SPP or SPP NITS POD has a Transmission Reservation

charge of zero 2. Pay for Transmission to non-Market SPP TO (allocate some transmission revenue)

o Address in discounting policy (exclude certain paths) or address explicit recovery in the Tariff

3. Do not reduce ATC for transmission that is reserved for external generation and not charged o Reservation granted, but in near real-time Tag may be denied by Transmission Provider o Areva non-firm experience calculator o Increase TLR expectation or increase RNU

4. No LSE (PSE) undue rejection of Tag o MP for external generation registers both the source and a sink Settlement Location. o SPP is the sink Settlement Location o Tariff language restricts LSE from rejection of Tag

5. No external generator or LSE hoarding of Transmission Reservations o Market Monitor responsibility to monitor o Do not reduce ATC for transmission that is reserved for external generation and not

charged 6. Sink BA visibility of external generator impacts (both in/out) – aggregate schedules

o SPP explicitly identify external generator aggregate impacts on BA NSI o SPP is the sink “BA”

7. Sink BA ability to call for reserve assistance o Criteria change to allow contingencies for loss of non-firm schedules

8. No Fault to BA for impact of External Generators (regulation, reserves, etc.) o Tariff language to allow recover cost from external generator

9. Market and system design cannot reduce ability of sink BA to meet CPS requirements o Tariff language allowing recovery of fines directly related to the external generators o SPP is the sink “BA”

Page 9 of 21



PRR Number 137 PRR

Title External Resources in the SPP Market




Section 3.1, 4, 5, 6 and create a new section 7 named External Resources in the SPP EIS Market (Current section 7 will move to 8 and so on).

Revision Description Propose a solution for allowing External Resources to participate in the SPP Market within 3 months of market start.


Approved with 1 no vote (Westar) and 1 abstention (Xcel) in the February 6-7, 2007 MWG meeting.

RTWG Review

ORWG Review


Original Sponsor Name SPP Staff Company Southwest Power Pool


Page 10 of 21




3.1 Introduction The Resource Plan is submitted by Market Participants with registered Resources to enable the SPP Market Operation System (MOS) to assess Resource and Ancillary Service adequacy for the SPP region, each SPP control area, and each Market Participant. The operator of the Control Area remains responsible for the balance of Load and Resources within the Control Area boundary. See Appendix 7 of SPP Criteria for requirements of data submission.

External Resources, participating in the SPP EIS Market, have the same requirements for submitting a Resource Plan as those Resources within the SPP Market Footprint, except as specified below. If an External Resource is a generating unit, all or a portion of the unit’s capacity may be offered into the SPP Market. For such External Resource capacity as is offered into the SPP Market, (i) only status available to External Resources is “Available” or “Unavailable”; and (ii) the Min MW should be set to zero and the Max MW will be the amount offered into the SPP Market.

4.1 Introduction Each MP submits its Ancillary Service Plan to enable the SPP Market Operation System to confirm each MP is satisfying its Ancillary Service obligations. The Ancillary Service Plan indicates transfers of Energy Obligations between MPs and, when self provided, which Resources are providing these services. Ancillary services are supplied and procured in accordance with the provisions of the SPP tariff and applicable SPP criteria.

MP’s must indicate on the AS Plan Reserves and Regulation (Spin, Supp, Upreg, Downreg) sufficient to meet their Energy Obligations. MP’s may also designate Reserves and Regulation in excess of their Energy Obligations for reliability purposes. It is recognized that in some instances a party may indicate capability being held for Regulation or Reserve service that is actually being reserved to indicate emergency operating capabilities or other operating capabilities and commercial limitations of the Resource.

External Resources, participating in the SPP EIS Market, will not be responsible for submitting Ancillary Service Plans.

Page 11 of 21



5.1 Introduction To submit an offer an Market Participant must have executed the service agreement as specified in Tariff Attachment AH. Offer Curves are submitted by Resource. Resources that offer energy into the SPP EIS market must specify an offer price. The price is specified using an Offer Curve. The Offer Curve allows Resources to offer multiple points at different prices. An Offer Curve is submitted for each Resource with up to ten monotonically increasing pairs of MWh and price. The price may be positive or negative and may be capped. See Section 11 for further details. Owners of Joint Owned Units may agree to register the units as separate Resources.

External Resources, participating in the SPP EIS Market, have the same requirements for submitting an Offer Curve as those Resources with-in the SPP Market Footprint.

6.1 Introduction Energy schedules are submitted reflecting bilateral and Self-dispatched activities. Source and sink information on the energy schedules must match the NERC Registry. Schedules that source or sink within the SPP Market will be rejected if they are submitted without an appropriate SPP source and/or sink mapped to a Settlement Location. SPP requires all scheduled injections to equal scheduled withdrawals plus losses. Although scheduling of all Load is not required, principles observed are (1) Market Participants will not be paid (due to under-scheduling) for providing counterflow when serving firm Energy Obligation (Resources providing energy that serves their firm Energy Obligation), and (2) Market Participants will not be allowed to profit from submitting schedules in excess of their firm Energy Obligations.

The External Resource may obtain any type of Transmission Service (firm or non-firm, of an duration) sourcing at the Resource and Sinking at a BA within the SPP EIS Market footprint. The Market Participant will submit Dynamic Dispatchable Schedules and SPP will communicate the dispatched generation values for the Dynamic Dispatchable Schedules to the Source BA in real time for their incorporation in the Source BA NSI. The integrated final schedule values would be utilized only for check-out and as the metered actuals of the External Resource for settlement purposes. The integrated final Schedule values will not be included in the Schedule totals of the Sink location for EIS purposes.

SPP will adjust the NSI for the Sink BA (internal to SPP market footprint) for the Deployment signal to the External Resource. SPP will dispatch those External Resources with valid Dynamic Dispatchable Schedules economically for imbalance purposes.

7 External Resources (move sections down to insert this section)

Page 12 of 21



7.1 External Resources in the SPP Market

The owner of an External Resources that wishes to participate in the SPP EIS Market, with that Resource must register with SPP as a Market Participant. The External Resource, if not currently modeled, will be modeled at an external node based upon the physical flow characteristics or a location that is electrically equivalent. Once an External Resource is adequately modeled and can feasibly participate, that Resource can be offered into the SPP EIS Market, or held out of the SPP EIS Market to participate in another market, as that Resource chooses. These Resources will not be required to provide ICCP and Settlement Meter data. The LIP calculated for the External Resource Settlement Location is the product of (i) the estimated distribution of modeled energy flows across specific interface points between SPP and adjacent Balancing Authorities and (ii) the Locational Imbalance Price at each interface point.

These External Resources will be responsible for submitting Resource Plans and Offer Curves and must follow the same timelines and procedures as outlined in these Market Protocols. The External Resource may utilize any type of Transmission Service (firm or non-firm, of any duration) sourcing at the External Resource and sinking at a BA within the SPP EIS Market footprint. The Market Participant will submit Dynamic Dispatchable Schedules and SPP will communicate the real-time dispatched values for the Dynamic Dispatchable Schedules to the Source BA in real time for their incorporation in the Source BA’s NSI. The integrated final schedule values would be only utilized for check-out and as the metered actuals for settlement purposes. As a result all energy from an External Resource using this provision is considered imbalance energy. The integrated final Schedule values will not be included in the Schedule totals of the Sink location for EIS purposes.

SPP will adjust the NSI for the Sink BA (internal to SPP market footprint) for the Deployment signal to the External Resource. SPP will economically dispatch those External Resources with valid Dynamic Dispatchable Schedules for imbalance purposes. This solution will result in the potential reduction in uplift charges due to real-time deployment and allow participation of entities within and beyond SPP’s 1st tier.

In the event of a curtailment of the Dynamic Dispatchable Schedule from the External Resource, the Sink BA is able to utilize RSS under an “Other Extreme Conditions” category, if necessary, when the Dynamic Dispatchable Schedule is curtailed. As a result, the recovery of the RSS costs would be under the FERC order process from the Market Participant with the Resource.

If the Source BA does not curtail the Schedule, then the Reserve Energy Deployment and any associated cost recovery is the responsibility and concern of the external Source BA.

Page 13 of 21

1

Strategic Planning Committeereport to

SPP Board of Directorsand

Members’ Committee

April 24, 2007Oklahoma City. OK

SPC Meeting – April 12, 2007

• MOPC Update • Regulatory Update

– Order 890 (OATT Reform)– Order 693 (Mandatory Reliability Standards)

• Organizational Effectiveness Action Plan• Strategic Plan Prioritization• Demand Response Presentation• NERC/RE Update

2

SPP Strategic Plan

• Transmission Expansion/Economic Upgrades– Recommend task force be developed

administratively reporting to the SPC to develop and recommend:

• Policy for allocation of right and responsibilities for construction of economic upgrades.

• Policy for regional standardization of transmission design criteria.

1

SPP Presentation

2

Human Resources Committee

Report to the Board of Directors

April 24, 2007

3

Human Resources Committee

DirectorDirectorOklahoma Municipal Power AuthorityTenaskaEmpire District Electric CompanyKansas City Power & Light

SPP Staff Representative

Quentin Jackson, ChairPhyllis BernardHarry DawsonTrudy HarperMike PalmerRichard Spring

Tom Dunn

Company Representative

3 4

Recommendation to the Board of Directors

The committee approved the following recommendation at the January 22, 2007 HRC meeting. “The Human Resources Committee recommends the Southwest Power Pool Board of Directors approve establishment of a Roth option as part of the SPP 401(k) plan.Action Requested: Approve Recommendation

5

2007 Compensation Survey

The committee is providing oversight to a compensation survey.

♦ Hay Group, Inc. is conducting the survey.

♦ Interviews with SPP officers and directors at the Little Rock office on May 3rd and 4th.

♦ Complete report delivered to HRC June 13th.

♦ Project cost: $89,500, plus travel expenditures for Hay Group. This is an unbudgeted item.

6

Staffing Report

Statistics as of April 17, 2007:♦ 257 full time employees, 2 part

time employees♦ 21 employees hired YTD 2007♦ 6 terminations YTD 2007♦ YTD 2007 turnover ratio: 2.0%♦ 31 remaining positions to hire, 10

outstanding offers

2

7

Benefit Plan Reviews

The committee reviewed the performance, investment statements, and plan designs of the following:♦ Defined Benefit Pension Plan♦ 401(k) Plan♦ Retiree Healthcare

8

Defined Benefit SERP Recommendation

The committee is addressing deficiencies in the SPP Retirement plans which disadvantage certain employees due to their compensation level.♦ The committee believes that

establishing a non qualified 457(f) supplemental executive retirement plan will correct this deficiency.

♦ The committee will bring a recommendation to the Board at the July 24, 2007 meeting.

9

Other Business

Reviewed the 2006 Performance Compensation ProcessDiscussed plans for future meetings.Committee will conduct a planning retreat June 13 & 14 in Little Rock.

10

Contact SPP

http://www.spp.orgGeneral Inquiries: 501-614-3200

Southwest Power Pool, Inc. HUMAN RESOURCES COMMITTEE


Organizational Roster The following members represent the Human Resources Committee:

Quentin Jackson, Chair Phyllis Bernard Trudy Harper Harry Dawson Mike Palmer Richard Spring

SPP Director SPP Director Tenaska Oklahoma Municipal Power Authority Empire District Electric Company KCPL

Background Southwest Power Pool, Inc. (“SPP”) sponsors a 401(k) savings plan for employees. This plan is utilized by employees to save for their retirement. SPP employees have requested a Roth option to their 401(k) savings plan. A Roth option will allow a participant to defer after-tax dollars to the 401(k). At retirement, the participant will be able to withdraw both the deferred amounts as well as the earnings on the deferred amounts tax free.

Analysis The Human Resources Committee reviewed the employee requests to implement a Roth option in the SPP retirement plan package. SPP staff determined that a Roth option could be added to the existing 401(k) package at no cost to SPP, and at minimal work requirements from SPP staff. This option will be administered by the same provider as the 401(k) plan. Implementing a Roth option to the SPP retirement package will ensure that the retirement savings plans offered to SPP employees are robust.

Recommendation

The Human Resources Committee recommends the Southwest Power Pool Board of Directors approve establishment of a Roth option as part of the SPP 401(k) plan.

Approved: Human Resources Committee January 22, 2007


Agenda Item 6-1

1

SPP.org 1

SPP Finance Committee Report

Harry Skilton

April 24, 2007

SPP.org 3

Finance Committee Roster

DirectorDirectorAmerican Electric PowerArkansas Electric CooperativesTenaskaWestar Energy

Harry Skilton, ChairLarry AltenbaumerDavid SartinGary VoigtTrudy HarperKelly Harrison

Non-Voting Members

Southwest Power PoolSouthwest Power Pool

Nick BrownTom Dunn

Company Representative

SPP.org 4

Meetings

• Met three times since last SPP Board of Director meeting:

• January 31 – San Antonio

• April 12 – Oklahoma City

• April 18 – Teleconference

SPP.org 5

Discussion Agenda

• 2006 Financial Report

• Capital Expenditure Policy / Financing

• Credit Policy Changes

• Financial Security Requirements

• Settlement Timelines

• SPP Controls (SAS70 Type II Audit)

SPP.org 6

2006 Financial Report

• Reviewed audit report with BKD, LLC

• Audit opinion was unqualified

• No material weaknesses in process or procedures

• Significant improvement noted in audit adjustments and management controls

2

SPP.org 7

2006 Financial Report (cont.)

MOTION

• SPP Board of Directors accept in its entirety 2006 audit report and findings of BKD, LLC

SPP.org 8

Capital Expenditure Policy / Financing

• Confirmed policy of funding capital expenditures with debt financing

• Approved 2007 Financing strategy:

• Issue $30 million in term debt with structured principal payments through 2014. Facility expected to fund capital expenditures incurred in last half of 2006, 2007 and 2008.

• Issue $20 million revolving credit facility maturing in 2012. Provides liquidity to meet debt covenants and bridge short-term working capital needs.

SPP.org 9


UnsecuredUnsecuredCollateral

1.25 : 11.0 : 1Fixed Charge

StructuredPrincipal Pmts

20122014Maturity

L + 50 bps, floatL + 30bps (~5.30%)Rate

RevolverTerm NoteType

$20,000,000$30,000,000Amount

JP Morgan ChaseUS BankLender

SPP.org 10


MOTION

• SPP Board of Directors resolves to borrow $30 million from US Bank on terms indicated in US Bank’s term sheet and SPP Board of Directors resolves to borrow $20 million from JP Morgan Chase on the terms indicated in the JP Morgan Chase term sheet. The SPP Board of Directors authorizes the SPP President and CFO to jointly execute all evidence of the above indebtedness.

SPP.org 11


• SPP staff directed to submit filing to Arkansas Public Service Commission requesting authority to issue $30MM in term financing and $20MM in revolving notes.

• SPP Board of Directors reaffirms policy of funding capital expenditures with debt financing structured to retire coincident with expiration of accounting useful life of assets acquired.

SPP.org 12

Credit Task Force Actions

• Approved change in Credit Policy such that suspension of unsecured credit limit not triggered if payment is received by cure date

• Approved reduction in cure period for transmission service to 3 days from 10 days

• Approved other miscellaneous changes to Credit Policy to clarify intent

3

SPP.org 13

Financial Security Requirements for Transmission Customer Where Upgrades are Required

• Approved language drafted by RTWG which reduced obligation to post financial security for transmission upgrades to only those costs which are directly assigned

• Approved addition of phrase “or other forms of financial security acceptable to Transmission Provider” to definition of acceptable financial security

SPP.org 14

Market Settlement Timeline

• Concerned settlement timelines for EIS market continue to expand.

• PRR-134 extended issuance of initial settlement statement to 7 days following operating day (from 5 days).

• PRR-140 extends issuance of final settlement statement to 47 days following operating day (from 45 days).

SPP.org 15


• Finance Committee strongly believes timelines should move in opposite direction to reduce participants’ exposure to defaults and to ensure excellence and confidence in SPP’s market.

SPP.org 16


MOTION

• SPP Board of Directors direct Markets and Operations Policy Committee to make necessary changes to protocols to allow issuance of initial settlement statements less than 7 days after operating date.

• Initial settlement statement timeline changes should be provided to Finance Committee in advance of September 19, 2007 meeting.

SPP.org 17

SPP Controls (SAS70 Type II Audit)• Engaged PwC to perform an agreed upon

procedures review of SPP’s “high risk” control activities related to EIS operations

• PwC review indicated substantial work remains to ensure controls are effective

• Several control exceptions noted in 2006 SAS70 audit are in process of being remediated.

Tom DunnVP, Finance & Chief Financial [email protected]

Southwest Power Pool, Inc. FINANCE COMMITTEE


2006 Financial Statement Audit

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

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

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

Background SPP annually engages a Certified Public Accounting firm to audit its financial statements. The audit report serves to document to members, customers, and other interested parties that the accounting practices and financial reporting of SPP comply with generally accepted accounting principles in the Unites States of America. SPP Board of Directors at its October 24th, 2006 meeting accepted the recommendation of the Finance Committee to engage BKD, LLC (BKD) to perform the 2006 audit.

Analysis BKD has completed and published its audit of SPP’s 2006 financial statements. The Finance Committee, at its April 12th, 2007 meeting met with representatives of BKD and discussed their findings.

Recommendation The Finance Committee recommends the SPP Board of Directors accept in its entirety the 2006 audit report.

Approved: Finance Committee April 12, 2007




2007 Financing


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

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

Background The Southwest Power Pool, Inc. (“SPP”) capital structure currently consists of the following term notes:

Notes Rate Original Balance Current Balance Payments

2008 Sr Notes 7.50% $25,000 $5,000 $5,000 annually 2011 Sr Notes 4.78% $25,000 $25,000 $5,000 annually 2027 Sr. Notes 6.36% $5,140 $5,140 $51 annually The 2008 and 2011 senior notes are unsecured. The 2027 senior notes are secured by a mortgage on SPP’s primary operations facility and improvements. SPP also has available a $8,000 unsecured revolving line of credit maturing May 2008. The revolving line currently has $4,000 advanced against the $8,000 commitment.

The SPP Finance Committee reaffirmed SPP’s policy of funding capital expenditures with term financing at its January 31, 2007 meeting. Additionally, the Finance Committee authorized SPP staff to negotiate $30,000 in term financing and $20,000 in revolving credit. Proceeds from the term facility will fund the following capital expenditures:

$4,000 Replenish operating cash used to fund 2006 capital expenditures $19,000 Fund approved 2007 capital expenditures $7,000 Fund expected 2008 capital expenditures The revolving credit facility will be used to supplement SPP’s short-term working capital needs as well as satisfy the liquidity requirements of SPP’s various credit agreements1

1 Term debt agreements require SPP maintains 6 months of principal and interest payments

Analysis SPP received financing indications for the term facility from numerous lenders; the best fixed and floating rate indications are detailed below:

PRUDENTIAL US BANK

Amount $30,000 $30,000

Rate Fixed T+110bps Floating L+30bps

Advance Period 2 Years2 2 Years

Interest Payments Quarterly Monthly

Principal Payments $1,500 quarterly Per schedule to retire debt in 2014

Fees $30 initiation + 1/8% of each advance

None

Fixed Charge Ratio 1.0 : 1 1.0 : 1

Yield Maintenance Yes No

SPP requested financing indications from three banks to provide a $20,000 revolving credit facility. Below is detailed the terms of the existing facility and the proposed facility:

Existing Facility Proposed Facility

Amount $8,000 $20,000

Maturity May 2008 May 2012

Interest Rate L + 100bps L + 50bps2

Unused Fee 17.5 bps 10 bps

Agent Fee N/A $10 annually

Interest Coverage Ratio 1.25 : 1 1.25 : 1

SPP’s ability to issue debt securities is regulated by the Arkansas Public Service Commission. Following approval by the SPP Board of Directors, SPP will make a filing to the Arkansas PSC requesting authority

2 “PruShelf” facility not a commitment 2 Credit margin on sliding scale based on SPP’s credit rating (currently BBB)

to issue the term and revolving notes. We anticipate the AR PSC issuing its approval order between 45 and 60 days of SPP’s filing. Issuance of the notes is expected to occur quickly following receipt of a favorable order from the AR PSC.

Recommendation Recommend to SPP’s Board of Directors the selection of US Bank to provide term financing as indicated in their proposal.

Recommend to SPP’s Board of Directors the selection of JP Morgan Chase to provide a revolving credit facility as indicate in their proposal.

SPP staff is directed to submit a filing to the Arkansas Public Service Commission requesting authority to issue $30,000 in term financing and $20,000 in revolving notes.





Initial Settlement Date for EIS Market Transactions


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

Director Director Tenaska Arkansas Electric Coop Westar Energy AEP

Background The Finance Committee, at its December 11, 2006 meeting, endorsed PRR-134 which established the date for issuance of initial settlement statements for EIS market transactions as 7 days following the operating day. The Finance Committee asked the Market Working Group to report back to the Finance Committee following implementation of the EIS market to discuss the effects of PRR-134 and what steps need to be taken to accelerate the issuance of initial settlement statements.

Analysis The extension of the date to issue initial settlement statements exposes all market participants to greater exposure to defaults. While the extension appears to have been beneficial in the initial operation of the EIS market, it is the desire of the Finance Committee to reduce the exposure participants have to defaults of market participants. Reduction in the days between the operating day and the issuance of the initial settlement statement is a very straightforward approach to meaningful reduction in risk.

Recommendation The Finance Committee recommends the Board of Directors direct the Markets and Operations Policy Committee to make the necessary changes to the meter data submission timeline to allow for posting of initial settlement statements less than 7 days after the operating date. The initial settlement statement timeline changes should be provided back to the Finance Committee in advance of its scheduled September 19, 2007 meeting.



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