Southwest Power Pool. BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING Marriott Tulsa Southern Hills, Tulsa, OK October 28, 2008

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1 Southwest Power Pool BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING Marriott Tulsa Southern Hills, Tulsa, OK October 28, Summary of Action Items - 1. Approved Consent Agenda items: a. Approved minutes from the July 29 and September 8, 2008 Board of Directors/Members Committee meeting. b. Approved the Finance Committee s Credit Policy modification for Guaranty Agreement representations and warranties. c. The Markets and Operations Policy Committee s recommendations to approve: 1. Criteria 5 modifications 2. Tariff language for the newly created Attachment AP 3. Tariff changes regarding the Project Sponsor Agreement allowing the RTWG to make any non-substantive changes to the Tariff language necessary for filing at the Commission 4. PRRs 184 and 186 for incorporation into the Market Protocols 5. Non-substantive Tariff language modifications of Schedule 2 6. Attachment J waiver request for City of Coffeyville, KS 7. Cancellation of the Clay Center (Westar) Greenleaf (MKEC) project as an SPP regional reliability project and the cancellation of the associated NTCs. The MOPC recommends for Board of Directors approval, the inclusion of the Knob Hill (Westar) Steele City (NPPD) and the Kelly South Seneca (Westar) projects, which will replace the Clay Center Greenleaf project, as needed for SPP regional reliability in the current approved STEP. 2. Approved the Finance Committee s recommended 2009 Operating and Capital Budget. 3. Approved the Finance Committee s recommendation that SPP establish an assessment rate and Tariff administrative fee rate (schedule 1A) of 17 /MWh effective January 1, Approved the Market and Operations Policy Committee recommendation to approve the Attachment J waiver request for Westar. 5. Approved the Market and Operations Policy Committee recommendation to approve revised Tariff language to include Nebraska entities in the Base Plan Funding.

2 MINUTES NO. 120 Southwest Power Pool BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING Marriott Tulsa Southern Hills, Tulsa, OK October 28, 2008 Agenda Item 1 - Administrative Items SPP Chair Mr. Jim Eckelberger called the meeting to order at 9:05 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. Julian Brix, director Mr. Nick Brown, director Mr. Jim Eckelberger, director Ms. Trudy Harper, Tenaska Power Services Company Mr. Kelly Harrison, Westar Energy Ms. Cindy Holman, Oklahoma Municipal Power Authority Mr. Rob Janssen, Dogwood Energy Mr. Jeff Knottek, City Utilities of Springfield Mr. Joshua Martin, director Mr. Steve Parr, Kansas Electric Power Cooperative 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. Rick Tyler, Northeast Texas Electric Cooperative Ms. Sandra Byrd, for Mr. Gary Voigt, Arkansas Electric Cooperative Company Mr. Rick Wolfinger, Constellation Power Source Mr. Eckelberger welcomed guests and asked for a round of introductions. There were 90 persons in attendance either in person or via phone representing 25 members (Attendance List - Attachment 1). Mr. Brown reported proxies and a quorum was declared (Proxies - Attachment 2). Agenda Item 2 Pending Action Items Report Ms. Stacy Duckett reviewed past action items (Past Action Items Attachment 3). Agenda Item 3 Regional State Committee Report Vice President David King presented the Regional State Committee (RSC) report. Mr. King stated that the RSC met on October 27 with all states represented. He welcomed Mr. Paul Suskie (Arkansas Public Service Commission) back to the group after having served in Iraq. Items discussed and approved were: Conducted the Annual Election of Officers electing the following members to serve beginning January 2009: President David King Vice President Michael Moffet Secretary/Treasurer Jeff Davis 2

3 SPP Board of Directors/Members Committee Minutes October 28, 2008 FERC and the Regional Entity Trustees Updates Approved the 2009 Budget and the 2007 Audit Report Business Items: o Electric Transmission America, OG&E Energy and Westar Energy reports regarding the 765 kv overview and cost benefits o Voted unanimously to recommend the Westar and Coffeyville Attachment J waiver request to the Board of Directors o Voted to endorse unintended consequences for the 2007 STEP as reviewed by the Regional Tariff Working Group (RTWG) and reported to the Markets and Operations Policy Committee and the RSC o Reviewed future markets cost/benefit studies o SPP Strategic Plan update Mr. King expressed appreciation for the work of Ms. Julie Parsley as past President of the RSC. Mr. Jim Eckelberger also thanked Ms. Parsley for her great leadership in bringing change and recognition by FERC. Agenda Item 4 Federal Energy Regulatory Commission Report Mr. Patrick Clarey introduced Ms. Penny Murrell, OEMR Central Director of FERC. Mr. Clarey then provided an update on FERC activities. At the September open meeting, the Commission: Finalized a rule requiring all tariff filings by public utilities, natural gas pipelines and oil pipelines be made electronically. Implementation of this requirement will begin in 18 months to permit sufficient time for software development. Conditionally granted incentive rates for the New York Regional Interconnect project subject to the New York Public Service Commission s determination that the project either ensures reliability or reduces congestion and approves siting for the project. Approved an experimental plan by a group of Western transmission providers for a two-year experimental regional transmission pricing initiative intended to encourage more efficient use of the grid and reduce customer costs by expanding access to coordinated transmission service from multiple transmission providers. Also in September, the Commission approved notationally SPP s request for waiver of the Commission s requirement that SPP perform an audit of its independence from market participants in light of the Commission s on-going audit exploring similar issues. At the October open meeting, the Commission: Approved SPP s cost allocation proposal to establish a process for including a balanced portfolio of economic upgrades in the transmission expansion plan and to recover the cost of those upgrades through a regional postage-stamp rate. Approved incentive rates for major transmission projects in the Western United States and Maine. Finalized regulations to strengthen and improve organized wholesale market operations. The final rule generally tracks the proposals outlined in the February 2008 NOPR. These include directing the RTOs to implement rules to foster demand response participation in the markets, facilitate long-term power contracting, strengthen market monitoring and ensure responsiveness to customers and stakeholders. 3

4 SPP Board of Directors/Members Committee Minutes October 28, 2008 Also in October, the Commission held a technical conference regarding barriers to transmission development. The purpose of the conference was to hear from transmission developers, transmission owners and others on the issues they encounter when trying to build transmission. Other FERC-related events: On September 22, 2008 the United Sates Government Accountability Office (GAO) released their report on FERC s oversight of RTOs. The GAO found that RTO expenses vary considerably depending on the size of the RTO and the functions it carries out. Additionally the Report noted that RTOs and FERC rely heavily on the participation and views of stakeholders when evaluating RTO expenses and decisions that may affect electricity prices. The GAO stated that FERC, industry participants and experts lack consensus on whether RTOs have brought benefits to their regions that outweigh their costs. In light of these, GAO recommends that FERC develop an approach for regularly reviewing RTO budgets and annual financial reports, and develop and report on standardized measures that track RTO performance. FERC may look to the RTOs/ISOs in the context of the IRC as a platform to begin to discuss how to develop the performance metrics. Senior staff from OEMR continue their participation in ongoing outreach to the state commissions covered under classic SPP RTO as well as the SPP ICT arrangement with Entergy and the SPP ITO arrangement with EON. Staff plans informal meetings in connection with the NARUC meeting in New Orleans next month with states covered under the ICT arrangement. Agenda Item 5 Regional Entity Trustee Report Mr. Gerry Burrows provided a report on the Regional Entity (RE) Trustees activities. The report included: There have been 60 enforceable violations as of October 16, 2008 of which 95% are either self certified or self reported. The top six violations fall inline with the top seven NERC violations which include: o Protection System Maintenance and Testing o Facility rating Methodology o Protections System Misoperations Analysis o Establish and Communicate Facility ratings o Sabotage Reporting o Generator Operations/System Voltage Support 2009 audit schedule includes 21 combined on and off site audits SPP RE Fall Compliance Workshop September 23 24, 2008 was in Tulsa, OK. The next workshop is scheduled for February in Little Rock. RE conducted a survey of registered entities with approximately 50% participation and an overall favorable response. RE has hired a Lead Compliance Engineer which should help address an area identified as needing improvement, resolving problems in a timely manner. NERC Readiness Evaluations will continue per FERC order on the NERC 2009 NERC budget which directed NERC to continue funding the program. Mr. Eckelberger suggested that SPP Staff report to the Board on how to better prepare members in order to avoid violations. Agenda Item 6 President s Report Mr. Brown called attention to the Quarterly Report and the Corporate Metrics Report (Quarterly and Metrics Reports Attachment 4). Mr. Michael Desselle was asked to present the Metrics Report showing 4

5 SPP Board of Directors/Members Committee Minutes October 28, 2008 a dashboard view of transmission and Market indicators, financial metrics, learning and growth, and performance. It was requested that the metrics show how SPP compares with other RTOs and that all charts be on an annualized basis. Mr. Brown discussed a topic he presented last year regarding energy efficiency and demand response. He presented a history of the Energy Imbalance Market (EIS) and FERC s Order on Rehearing in 2006 to coordinate with utilities, state commissioners and other interested parties to consider provisions for participation of demand resources in the imbalance market. Currently SPP is working on incorporating demand response into its EIS Market and future markets, federal initiatives are growing and state initiatives are developing. SPP has provided and continues to provide compliance filings to FERC every six months. Mr. Brown also addressed excerpts from FERC s final rule regarding wholesale competition in regions with organized electric markets stating that FERC will not decide whether a regulator of a traditional, vertically-integrated monopoly utility may give permission for an ARC (aggregator of retail customers) to aggregate customers demand responses for bidding into SPP s markets. Mr. Brown encouraged members to discuss this issue with their companies and welcomes any comments. Agenda Item 7 Consent Agenda Mr. Eckelberger presented the following consent agenda items for approval (Consent Agenda Attachment 5): A. Approve July 29, 2008 Board of Director/Members Committee meeting minutes and September 8, 2008 teleconference minutes. B. Approve the Finance Committee s recommendation for Credit Policy modification regarding Guaranty Agreement representations and warranties. C. Approve Markets and Operations Policy Committee s (MOPC) recommendations: 1. Criteria 5 modifications 2. Tariff language for the newly created Attachment AP 3. Tariff changes regarding the Project Sponsor Agreement allowing the Regional Tariff Working Group (RTWG) to make any non-substantive changes to the Tariff language necessary for filing at the Commission. 4. PRRs 184 and 186 for incorporation into the Market Protocols 5. Non-substantive Tariff language modifications of Schedule 2 6. Attachment J waiver request for Westar 7. Attachment J waiver request for City of Coffeyville, KS 8. Cancellation of the Clay Center (Westar) Greenleaf (MKEC) project as an SPP regional reliability project and the cancellation of the associated NTCs. The MOPC recommends for Board of Directors approval, the inclusion of the Knob Hill (Westar) Steele City (NPPD) and the Kelly South Seneca (Westar) projects, which will replace the Clay Center Greenleaf project, as needed for SPP regional reliability in the current approved STEP. Mr. Eckelberger asked for requests to remove any items from the Consent Agenda or a motion to approve. 5

6 SPP Board of Directors/Members Committee Minutes October 28, 2008 Mr. Bary Warren (Empire District) asked that the Westar waiver request be removed from the Consent Agenda for discussion. Mr. Josh Martin moved to approve Consent Agenda items with the exception of the Westar waiver request. Mr. Larry Altenbaumer seconded the motion. The Members Committee voted in unanimous favor. The motion passed. Agenda Item 8 Finance Committee Report Mr. Harry Skilton provided the Finance Committee report (Finance Report & Presentation Attachment 6). The Committee s recent activities are: to amend the SPP Credit Policy (included in the Consent Agenda), directed review of liability insurance, and reviewed insurance protection for the proposed aircraft. Action items include: 2009 Operating and Capital Budgets Mr. Skilton presented the 2009 Budget (SPP 2009 Budget Attachment 7). He reviewed: capital expenditures, expense analysis, staff growth, revenue analysis, and the Tariff administration fee. In discussion it was asked what the process would be regarding SPP s plan to build a new administrative office and primary operations facility. A building plan will be presented to the Finance Committee in December 2008 and subject to final approval at the January 2009 Board meeting. Following discussion, Mr. Skilton moved to approve the 2009 SPP Operating and Capital Budget as submitted. Mr. Larry Altenbaumer seconded the motion. The Members Committee voted in unanimous favor. The motion passed Administrative Fee Mr. Skilton stated that the Committee recommends SPP establish an assessment rate and Tariff administrative fee rate (schedule1a) of 17 /MWh effective January 1, He moved that the Board approve this recommendation. Mr. Josh Martin seconded the motion. The Members Committee voted in unanimous favor. The motion passed. Agenda Item 9 Markets and Operations Committee Report Mr. John Olsen provided the Markets and Operations Policy Committee Report (MOPC Recommendations & Presentation Attachment 8). Mr. Olsen presented the following action items for approval: Westar Waiver Request Westar requested a waiver under Attachment J for costs in excess of the Safe Harbor Cost Limit for Base Plan funding. The CAWG/RSC recommended granting Westar a waiver in accordance with the RSC approved new policy for the direct assignment portion for wind resources. This would approve 67% of the upgrade cost to be regionally funded and directly assign 33% to Westar. Mr. Olsen asked the Board to approve the MOPC recommendation for the Westar waiver as outlined by the CAWG with no dollar cap. Mr. Nick Brown moved to approve the recommendation and Mr. Julian Brix seconded the motion. The Members Committee voted in unanimous favor. The motion passed. Tariff Language for Nebraska Entity Base Plan Funding Mr. Olsen provided background and Tariff language approved by the RTWG on October 23 to include the Nebraska entities in the Base Plan Funding (Revised Tariff Language Attachment 9). He requested Board s approval in order to file by November 1, Mr. Brix moved to approve the revised Tariff language and Ms. Phyllis Bernard seconded the motion. The Members Committee voted in unanimous favor. The motion passed. Mr. Olsen then provided the following informational items: Cost Benefit Task Force: Mr. Roy True (ACES) provided an overview of the cost benefit study. All 6

7 SPP Board of Directors/Members Committee Minutes October 28, 2008 analyses have indicated a benefit in excess of costs in all scenarios. Market Working Group: MOPC expects to have Tariff language for the December Board meeting for PRR 176 to clarify and enhance the requirements for Demand Response to participate in the SPP EIS Market. Consolidated Balancing Authority Steering Committee: The MOPC has directed the CBASC to determine if there are additional designs or proposals that would provide the benefits expected without future market steps and coordinate with MWG. Regional Tariff Working Group: o Generation Queue Task Force o Delivery Point Addition Task Force o Proposal on 3 rd Party Impacts: It was suggested to include suggestions in dealing with 3 rd party (cross boarder) impacts to the FERC Docket on Transmission Barriers to Entry. Wind Integration Mr. Stuart Solomon suggested that a process is needed to integrate new members into SPP similar to the process of bringing in the Nebraska entities. Mr. Stuart Solomon recommended that SPP staff, working through the Stakeholder process, develop a process for the integration of new members into SPP. Mr. Brown indicated that Staff would develop such a process. Agenda Item 10 Informational Items Human Resources Committee Ms. Phyllis Bernard provided the Human Resources Committee (HRC) Report. The HRC met on October 27 and discussed the following items: self-funding for health care, status of retirement funds, SPP arranged financial help, and staffing for 2008 through Ms. Bernard congratulated the Human Resources Department for training and development of new hires and continuing to maintain the SPP culture. Oversight Committee Mr. Josh Martin presented the Oversight Committee Report. The Committee met in Chicago on June 25. The group discussed Market Monitoring Unit (MMU) recommendations for rule changes to the Market Working Group (MWG). The Committee is pursuing a contract with Boston Pacific for External Market Advisor services for They will develop an RFP for External Market Advisor services for Mr. David Hodges (SPP) is helping conduct one day seminars immediately following the Regional Entity Compliance Workshops to provide information to members and registered entities regarding compliance, including best practices and samples. The group s next meeting is scheduled for December 8 in Dallas, the day prior to the Board of Directors meeting. Strategic Planning Committee Mr. Richard Spring provided the Strategic Planning Committee (SPC) report. The SPC discussed: Consolidated Balancing Authority Regulatory Updates Transmission Owner/Construction Task Force (TOCTF) GAO Audit Report Draft Strategic Plan Mr. Spring thanked Mr. Mel Perkins for his work in chairing the TOCTF that determines how transmission 7

8 SPP Board of Directors/Members Committee Minutes October 28, 2008 is built. Seven principles proposed by the TOCTF are: 1. Time Limitation 2. Selection Process 3. Qualification of a Party Selected to Construct 4. Transmission Owners Continuing Obligations 5. Revenue Recovery 6. Delay in Construction 7. New Transmission Owners Rights The TOCTF has drafted a Concepts Paper which is expected to be presented to the Board in January for approval. Future Meetings The next Board of Directors/Members Committee meeting is December 9, 2008 in Dallas, TX. The January 27, 2009 meeting is also scheduled in Dallas (Future Meetings Attachment 9). Adjournment With no further business, Mr. Eckelberger thanked everyone for participating and adjourned the meeting at 2:30 p.m. Stacy Duckett, Corporate Secretary 8

9 BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING AND ANNUAL MEETING OF MEMBERS October 28, 2008 Marriott Tulsa Southern Hills Tulsa, OK AGENDA 8:30 a.m. 3:00 p.m. CDT Annual Meeting of Members 1. Call to Order and Administrative Items...Mr. Jim Eckelberger 2. Corporate Governance Committee Report...Mr. Nick Brown a. Election of Directors b. Election of Members Committee Representatives c. Election of Regional Entity Trustee Overview/2009 Outlook...Mr. Nick Brown Adjourn for Board of Directors/Members Committee Meeting Board of Directors/Members Committee Meeting 1. Call to Order and Receipt of Proxies... Mr. Jim Eckelberger 2. Pending Action Items Report...Ms. Stacy Duckett 3. Regional State Committee Report... Mr. David King 4. Federal Energy Regulatory Commission Report... Mr. Patrick Clarey 5. Regional Entity Trustees...Mr. Gerry Burrows 6. President s Report...Mr. Nick Brown 7. Consent Agenda...Mr. Jim Eckelberger 8. Finance Committee Report... Mr. Harry Skilton 9. Markets and Operations Policy Committee Report...Mr. John Olsen 10. Informational Items a. Human Resources Committee...Ms. Phyllis Bernard b. Oversight Committee... Mr. Josh Martin c. Strategic Planning Committee...Mr. Richard Spring 11. Future Meetings...Mr. Jim Eckelberger Relationship-Based Member-Driven Independence Through Diversity Evolutionary vs. Revolutionary Reliability & Economics Inseparable

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16 Southwest Power Pool, Inc. BOARD OF DIRECTORS/MEMBERS COMMITTEE Pending Action Items Status Report October 28, 2008 Action Item 1. MOPC to develop a uniform calculation for NEL 2. Staff report in six months on results of the revisions to Section 28.4 of the SPP OATT/secondary network service 3. TWG to initiate technical analysis of implementation of EHV Overlay Study Date Originated Status 1/30/07 Pending 4/24/07 Pending 7/24/07 Pending 4. SPC to develop implementation plan for EHV Overlay Study 7/24/07 Pending 5. Statistics re: impact of non-spp TLRs on service sold by SPP. 4/22/08 Pending Comments Assigned to RTWG by MOPC. Filing pending inclusion in broader market filing, and assessment of Order 890 impact. Updated EHV Study presented to stakeholders March 28 for comment. Benefits analysis is pending. Assigned to SPC; pending TWG outcome. Operations is assessing how to approach.

17 SPP FINANCIAL STATEMENTS 3 RD QUARTER DISCUSSION ALL DOLLAR VALUES IN THOUSANDS SPP reported a net loss of $3,921 on revenues of $68,402 for the first nine months of FY 08 as compared to net income of $2,346 on revenues of $65,867 for the same period in FY 07. Gross revenues trailed budget by $1,319 and the net loss was less than the budgeted net loss by $3,376. REVENUES YTD administrative fee collections have decreased 2% from $42,932 in 2007 to $41,982 in The reduction in administrative fee revenue year over year is solely attributable to a slight reduction in billable load within the SPP footprint during Tariff administrative fees YTD account for 61% of SPP s total revenue stream compared to 65% in YTD Contract Services revenue increased 21% to $14,082 compared with the prior year. Additional billings related to satisfying the requirements of FERC Order 890 are responsible for the growth. Remaining revenue consisting of fees, assessments and miscellaneous income grew 10% YTD from $11,259 in 2007 to $12,338 in This growth is primarily due to an increase in engineering study activity as compared to EXPENSES YTD operating expenses increased 13% from $62,187 in 2007 to $70,302 in This growth is primarily due to an increase in staff and increased depreciation charges as 2008 represents the first full year where assets such as the Energy Imbalance Service (EIS) Market and Maumelle Operations Facility are depreciated. YTD personnel expenses totaled $30,713 in 2008 as compared to $25,462 in SPP has undertaken several initiatives during 2008 which have resulted in the growth in staff and corresponding increase in salary and benefit costs. Significant among these has been the full implementation of an operator in training program which positions SPP to respond to the forthcoming turnover as experienced operators leave the workforce. Additionally, SPP has added staff in its Settlements and IT groups as we move to insource support of our customer facing applications as well as replace our tariff settlement engine. YTD travel and meeting expenses have increased 34% as compared to 2007 and exceed budget by 9%. This expected increase is primarily due to addition of staff and Regional Entity activity. Additionally, travel expense has exceeded budget related to the rising unit cost of travel during the calendar year 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 EIS market. SPP has incurred $11,070 YTD in outside services expenditures for 2008 as compared to $11,506 in of 68

18 LIQUIDITY In early 2008, SPP executed the final draw of $10,000 on the 2014 Floating Rate Term Note. This additional borrowing along with $12,385 in cash provided by operating activities was used to fund $12,090 in capital expenditures and $11,654 in principle payments on long term loans. 3Q Q Q 2007 Unrestricted Cash $19,936 $24,386 $21,536 Current Ratio CAPITALIZATION SPP s balance sheet has above average leverage as a result of: 1) SPP s policy to finance capital expense projects with debt, and 2) a rate setting process intended to fund only budgeted expenditures. Expected net losses through the end of fiscal 2008 will further erode the Members Equity account and result in increased leverage measures. 3Q Q Q 2007 Members Equity $6,364 $10,285 $15,221 Long-Term Debt $41,126 $37,780 $38,383 Debt/Capital 87% 79% 72% Total Liabilities/Members Equity of 68

19 Southwest Power Pool Balance Sheet As of September 30, 2008 ($000) 09/30/08 12/31/07 Variance ASSETS Current Assets Cash & Equivalents $19,936 $24,386 ($4,450) Restricted Cash Deposits 17,735 14,644 3,091 Schedule 12 Deposits 5,865 9,393 (3,528) Accounts Receivable (net) 4,418 7,686 (3,268) Other Current Assets 2,969 2, Total Current Assets 50,922 58,305 (7,383) Total Fixed Assets 42,109 42,988 (879) Total Other Assets (22) Investments TOTAL ASSETS 94, ,379 (8,277) LIABILITIES & EQUITY Liabilities Current Liabilities Accounts Payable (net) 2,186 6,717 (4,531) Customer Deposits 18,335 14,644 3,692 Current Maturities of LT Debt 7,206 12,206 (5,000) Other Current Liabilities 13,482 15,426 (1,944) Total Current Liabilites 41,209 48,992 (7,783) Long Term Liabilities 4.78% Senior Notes ,000 15,000 (5,000) Floating Senior Note ,500 18,000 8,500 US Bank Mortgage ,626 4,780 (154) Other Long Term Liabilities 5,404 5, Total Long Term Liabilities 46,530 43,102 3,427 Net Income (3,921) (2,590) (1,332) Members' Equity 10,285 12,875 (2,590) Total Members' Equity 6,364 10,285 (3,921) TOTAL LIABILITIES & EQUITY $94,102 $102,379 ($8,277) 3 of 68

20 Southwest Power Pool Statement of Income For the Nine Months Ending September 30, 2008 ($000) Actual YTD 2008 Actual YTD 2007 Variance Actual YTD 2008 Budget YTD 2008 Variance Ordinary Income/Expense Income Tariff Administration Service $41,982 $42,932 ($951) $41,982 $44,733 ($2,752) Fees & Assessments 9,295 9, ,295 10,207 (912) Contract Services Revenue 14,082 11,677 2,406 14,082 12,865 1,217 Miscellaneous Income 3,043 2, ,043 1,916 1,127 Total Income 68,402 65,867 2,534 68,402 69,721 (1,319) Expense Salary & Benefits 30,713 25,462 5,251 30,713 32,802 (2,089) Employee Travel 1, , Administrative 1,683 1, ,683 1, Assessments & Fees 6,008 6,099 (91) 6,008 6,750 (742) Meetings Communications 1,852 1,971 (119) 1,852 2,101 (249) Leases (0) Maintenance 3,108 2, ,108 3,764 (656) Services 11,070 11,506 (435) 11,070 12,085 (1,014) Regional State Committee (145) Depreciation & Amortization 12,991 11,162 1,830 12,991 13,905 (914) Total Expense 70,302 62,187 8,115 70,302 75,544 (5,243) Net Ordinary Income (1,900) 3,681 (5,581) (1,900) (5,823) 3,923 Other Income/Expense Other Income Interest Income (257) (111) Total Other Income (257) (111) Other Expense Interest Expense 2,194 2,230 (36) 2,194 2,223 (30) Other Expense Total Other Expense 2,660 2, ,660 2, Net Other Income (Expense) (2,021) (1,334) (686) (2,021) (1,473) (547) Net Income (Loss) ($3,921) $2,346 ($6,267) ($3,921) ($7,297) $3,376 4 of 68

21 Southwest Power Pool Statement of Cash Flows For the Nine Months Ending September 30, 2008 ($000) OPERATING ACTIVITIES Net income (loss) ($3,921) $2,346 Adjustments to reconcile net income (loss) to new cash provided by operations: Depreciation 12,970 11,131 Amortization Changes in assets and liabilities: Schedule 12 deposits 3,528 2,463 Accounts receivable 3,268 (108) Other current assets (773) (44) Other assets (7) (424) Accounts payable (4,531) (2,081) Customer deposits 3,692 (2,288) Other current liabilities (1,944) (3,089) Other long term liabilities Net cash provided d by operating activities iti 12,385 8,595 INVESTING ACTIVITIES Purchase of property and equipment (12,090) (7,304) Net cash used by investing activities (12,090) (7,304) FINANCING ACTIVITIES Repayment on 7.50% Senior Notes (5,000) (5,000) Repayment on 4.78% Senior Notes (5,000) (5,000) Issuance of US Bank Mortgage Notes 5,140 Repayment on US Bank Mortgage Notes (154) (103) Draw on Senior Floating Notes 10,000 20,000 Repayment on Senior Floating Notes (1,500) Net cash provoded (used) by financing activities (1,654) 15,037 Net cash increase (decrease) for the period (1,359) 16,328 Cash at beginning of period 39,030 18,542 Cash at end of period $37,671 $34,870 5 of 68

22 SEPTEMBER PROJECT FINANCIALS Contract Services Update Manager: Bruce Rew (thousands of dollars) SPP s Contract Services department provides tariff administration and reliability coordination to utilities under specific contracts. Currently the business consists of two contracts implemented in 2006 which extend through SPP provided all required services under both contracts with the exception of an energy purchasing function. We have completed negotiations with the ICT and have approved 13 additional direct employees to support the additional compliance requirements for FERC Orders 890 and 693. Negotiation for additional staff with E.ON has been protracted. If agreement is not reached in November we will look for regulatory means to reach conclusion. The Contract Services department includes 58 positions with the new ICT contract (4 of which are vacant). SPP Contract Services continue to focus on customer improvement. The management team has defined targets for this year and is already having successes. The Acadiana Load Pocket transmission has been approved with Cleco, Entergy, and LUS participating. This transmission expansion will include both reliability and economic upgrades in the Lafayette, Louisiana area. The Weekly Procurement Process continues to face challenges in implementation with SPP and Entergy evaluating options to get the process started. Financially, SPP s revenues from the contracts exceeded budget even though both contracts are largely fixed price arrangements. The excess revenue over budget, and corresponding excess expense over budget, related to pass-through of cost related to legal and engineering services for tariff studies. YTD* YTD* Variance Actuals Budget Fav/(Unfv) Revenues: Contract Services Revenue $14,771 $12,865 $1,906 Other Member Services Total Revenues 14,771 12,865 1,906 Operating Expenses: Salaries & Benefits 4,566 4,401 (165) Other Expense 3,305 1,915 (1,390) Total Operating Expenses 7,871 6,316 (1,555) Capital Expenditures $18 $627 $609 *YTD Financials through September 2008 Does not include SPP overhead allocation Southwest Power Pool, Inc. 6 of 68

23 SEPTEMBER PROJECT FINANCIALS Settlements Processing Update Manager: Philip Bruich (thousands of dollars) High Level Project Scope: Significant upgrade of settlement engines for transmission and market services. Upgrades will support future market services and base and economic upgrade settlements. Major Milestones: Scheduled Actual/Projected Design June 13, 2008 July 8, 2008 Development July 21, 2008 August 25, 2008 Hardware Sept. 23, 2008 Sept. 23, 2008 Factory Testing-Mkt Sept. 26, 2008 November 21, 2008 Site Testing-Mkt October 31, 2008 December 31, 2008 Parallel Ops-Mkt December 31, 2008 February 28, 2009 Factory Testing-Trans Sept. 26, 2008 January 23, 2008 Site Testing-Trans October 31, 2008 March 1, 2009 Parallel Ops-Trans December 31, 2008 April 30, 2009 Current Status: Factory testing currently underway. Numerous test failures have uncovered configuration error which occurred in development phase. Approximately 30% of testing is complete. Anticipate market settlement engine can be fully tested and in place at March 1, Transmission settlement engine will likely be delayed until May Total forecasted expenses are currently tracking at $7,100, as compared with the $7,380 capital expenditure budget. Hardware is forecasted to be $900 as compared to a budget of $1,100 and includes setup for a hosted environment at a third party provider. Southwest Power Pool, Inc. SETTLEMENTS PROCESSING PROJECT BUDGET vs ACTUAL Expenses Projected Budgeted Invoiced Unbilled CapEx Amount To Date Expenses Remaining Software $5,000 $1,138 $3,472 $390 Hardware 1, Networking Consulting 1,140 1, (700) Total $7,380 $2,817 $4,557 $6 7 of 68

24 There is a separate initiative to support the Commercial Operations System (COS) applications for Portal and Siebel (Commercial Model) utilizing internal SPP staff. This includes 4 IT and 2 settlement staff additions. Five of these six positions were filled by April. This transition of support from Accenture to SPP staff is expected to be completed by 12/31/08. Southwest Power Pool, Inc. 8 of 68

25 SEPTEMBER PROJECT FINANCIALS Balancing Authority Consolidation Update Manager: Lanny Nickell (thousands of dollars) The MOPC formed the Consolidated Balancing Authority Steering Committee at their January 15-16, 2008 meeting. The CBASC has been working earnestly to complete conceptual design for the consolidated BA that was initiated in late spring The bulk of the work in 2007 was performed by a consultant contracting with SPP under the guidance of certain SPP Staff and a number of SPP BA representatives. The CBASC expects to complete the conceptual design prior to Summer Efforts to develop necessary agreements and contractual details have begun and are expected to be completed by this fall. Shari Brown was officially named as the Manager, Balancing Authority in late January. She is the primary staff person responsible for overseeing implementation of this project. When the budget for this project was created, it was envisioned that the consultant employed by SPP in 2007 would continue to be available and utilized for the first quarter of This has not been the case as his contract terminated at the end of Rather than renewing the contract, SPP chose to rely on Shari and the assistance of other staff that were involved last year to continue where the consultant left off. Other Balancing Authority staffing is not expected to begin as early as originally budgeted. SPP originally expected to begin hiring BA operators and other support staff as early as February and to continue hiring incrementally throughout the year. This expectation changed based on direction provided by the existing BAs in October of That direction was to continue work on developing concepts but to minimize, as much as possible, expenditures on BA consolidation until such time as a commitment for future market implementation is made. The decision for future market implementation is not expected prior to completion of an associated cost-benefit analysis, which is not expected until this October. Unless the direction previously provided is changed, the expenditure of Operating Expenses for this project will be significantly less than budgeted. YTD* YTD* Variance Actuals Budget Fav/(Unfv) Revenues: Tariff Fees & Assessments $0 $0 $0 Other Member Services Total Revenues Southwest Power Pool, Inc. Operating Expenses: Salaries & Benefits Other Expense Total Operating Expenses Capital Expenditures $0 $1,745 $1,745 *YTD Financials through September of 68

26 SEPTEMBER PROJECT FINANCIALS Data Warehouse Project Update Manager: Barbara Sugg (thousands of dollars) SPP is currently in the process of developing a Data Warehouse system to meet the following goals: (1) Replace the current Decision Support System due to aging hardware, increasing volumes of data, and system performance issues; (2) Develop a new data model that will enhance reporting and analysis; (3) Provide a user-friendly query tool for accessing the data without extensive training; (4) Implement a system that provides self-service methods of data retrieval; and (5) Create a central repository for handling nearly all of the real-time data feeds from existing systems at SPP. As of October, 2008, the Data Warehouse hardware platform has been determined and purchased following a proof-of-concept phase. The data migration and business intelligence tools have been selected and purchased. The data warehouse requirements for the Market Analysis department and the ITO have been documented and a plan has been developed. Approval was obtained in early October to contract with consultants to implement the data warehouse requirements. These consultants will be working side by side with SPP IT staff to configure the software, develop the data model, and populate the database according to the requirements previously defined. The total 2008 budget for the project is $4,050, which includes hardware, software, and consulting. Our current estimate to fully deliver the project is $4,590. We expect 2008 expenditures to total $3,000 with the remaining $1,590 to be spent in YTD* YTD* Variance Actuals Budget Fav/(Unfv) Revenues: Tariff Fees & Assessments $0 $0 $0 Other Member Services Total Revenues Operating Expenses: Salaries & Benefits Other Expense Total Operating Expenses Capital Expenditures $2,619 $3,360 $741 *YTD Financials through September 2008 Southwest Power Pool, Inc. 10 of 68

27 SEPTEMBER PROJECT FINANCIALS EIS Markets Update Manager: Richard Dillon (thousands of dollars) The EIS Markets became operational on February 1, Although history at other Regional Transmission Organizations showed that significant levels of settlement disputes would occur, SPP did not experience this level of disputes. The Dispute Resolution budget enabled SPP to staff with additional contractors to both handle the expected dispute levels and develop processes and computer programs to assist in dispute resolution. The EIS Market has continued to implement enhancements to the functionality based on requests from SPP Members and observations of SPP operations staff. The External Generator functionality was anticipated to become operational in The design was accepted in April 2008 and development is currently underway. Implementation is expected during first quarter The future market functionality is undergoing a cost/benefit analysis, expected to be complete in October After the cost/benefit analysis and detail design work has completed and reviewed by applicable groups and the Board of Directors, the vendor's will be engaged to develop software (expected at the end of 2008 or beginning of 2009). (000's) 2007 Project YTD* 2007 YTD* Variance to Date Act Actuals Carryover Budget Fav/(Unfv) Revenues: Tariff Fees & Member Assessments $0 $0 $0 $0 $0 Other Member Services Total Revenues Operating Expenses: Salaries & Benefits 1, Other Expense 27, Total Operating Expenses 28, Capital Expenditures $42,629 $976 $1,400 $310 $734 *YTD Financials through September 2008 Southwest Power Pool, Inc. 11 of 68

28 SEPTEMBER PROJECT FINANCIALS SPP Regional Entity Update Manager: Michael Desselle (thousands of dollars) To date, all program areas are tracking man-hours near the budgeted FTEs. The Compliance Enforcement program is above the 3 rd quarter amount primarily due to hours logged by one additional staff that was not included in the 2008 Budget. The Training program has the most hours attributing to the variance. The SPP Training group is short 1.5 FTEs since May due to staff changes. Open positions are expected to be filled during the fourth quarter, but hours logged to the RE are not expected to close the difference by the end of the year. The SPP Training group has also been asked to be diligent in entering RE related man-hours into JourneyX. The SPP RE Trustees approved two out-of-budget staff additions for the SPP RE under the Compliance and Enforcement Program and General and Administrative program areas. These staff additions are reflected in the 2008 full year projections which result in an expected unfavorable variance as compared to the 2008 full year budget. The projected overage to the 2008 RE Budget is $204. SPP RE does not plan to request additional funding for these two positions and will true up the overage in the 2009 Budget year. (000's) YTD* YTD* Variance Actuals Budget Fav/(Unfv) Revenues: Regional Entity Revenues $2,986 $3,457 ($471) Other Member Services Total Revenues 2,986 3,457 (471) Operating Expenses: Salaries & Benefits 1,037 1, Other Expense 1,949 2, Total Operating Expenses 2,986 3, Capital Expenditures $0 $0 $0 *YTD Financials through September 2008 Southwest Power Pool, Inc. 12 of 68

29 RELIABILITY COORDINATION SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT 3Q 2008 TLR Events per Quarter # of Events Q-08 2Q-08 1Q-08 4Q-07 3Q-07 SPP Q08 v. 3Q07 shows a slight decrease. MWh Curtailed due to TLR MWh Q-08 2Q-08 1Q-08 4Q-07 3Q-07 Firm Non-Firm 3Q08 v. 3Q07 shows a decrease in MWh curtailed due to TLR. 13 of 68

30 SCHEDULING SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT 3Q 2008 Daily Average Tags Processed Number of Tags Q-08 2Q-08 1Q-08 4Q-07 3Q-07 SPP Q08 v. 3Q07 shows a decrease in the number of tags processed. 14 of 68

31 TARIFF ADMINISTRATION SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT 3Q 2008 Total Requests Submitted Q-08 2Q-08 1Q-08 4Q-07 3Q-07 SPP Q08 v. 3Q07 shows a decrease in total transmission service requests. % of Total Requests that are Confirmed 70% 60% 50% 40% 30% 20% 10% 0% 3Q-08 2Q-08 1Q-08 4Q-07 3Q-07 SPP 48% 52% 58% 59% 41% 3Q08 v. 3Q07 shows an increase in percentage of transmission service requests confirmed. 15 of 68

32 QUEUE STATUS REPORT SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT 3Q 2008 Transmission Service Request Queue Number of study requests = 406, representing 34,659 MW Number of study requests for non-dc Tie = 264, representing 18,631 MW Number of DC Tie requests = 142, representing 16,028 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 = 202, representing 17,801 MW. Number of DC Tie requests = 209, representing 18,380 MW - These could not be processed due to impending DC Tie competition. Generation Interconnection Queue Number of active requests = 182, representing 46,599 MW Number of wind requests = 165, representing 43,931 MW Number of fossil fuel requests = 13, representing 2,542 MW Number of other = 4, representing 126 MW Number of requests with Interconnection Agreement pending = 10 Interconnection Agreements signed during 2008 = 5 (2 for Fossil for 246 MW and 3 for wind for 317MW not included above) During the same period last year, there are 69 requests in process (58 wind; 11 fossil fuel) representing 17,088 MW (12,639 MW wind; 4,449 MW fossil fuel). There were 11 Interconnection Agreements pending. 16 of 68

33 Southwest Power Pool, Inc. REGULATORY AFFAIRS Regulatory Update Third Quarter 2008 SPP Regulatory staff is currently tracking 421 cases at the state and federal levels, an increase of 83 cases since the close of the second quarter. Regulatory activity at the federal level increased slightly to account for 87% of SPP s current regulatory caseload. An overview of significant regulatory activities arising in the third quarter of 2008 is presented below. 1 For additional information, please refer to the detailed docket status report posted on the SPP website. A. SPP EHV Overlay Assessment SPP Staff is in the process of conducting analysis for the 2008 EHV Overlay Report. This analysis will primarily focus on economic analysis for EHV expansion with considerations given to how the plan should adapt for certain key economic drivers and assumptions. According to the current study timeline, the study should be complete by mid-december B. Joint Coordination System Plan JCSP work continues on schedule with study completion targeted by year's end. JCSP plans are complimentary to the EHV Overlay Plans for SPP. JCSP is focusing on reliability and economics in 2018 and 2024, respectively. Two scenarios are framing 2024 economic assessments. Reference case reflects 26 state/dc RPS as of 1/1/08 which equate in aggregate to an effective 5% RPS for Eastern Interconnection. Most of existing RPS for Eastern Interconnection are in the great lake states and Northeast. Since models were created, MI and OH have implemented RPS and other states are increasing requirements or getting new ones approved. Other scenario is a 20% Wind Scenario. Those models assume incremental wind development would be in best wind zones - central US plains to address a 20% National RPS. Results of these studies will be very beneficial in demonstrating the value of major EHV expansion in Eastern Interconnection. Transmission to support optimal expansion for Reference and 20% Wind scenarios amounts to roughly $57B and $80B, respectively. Assuming an 15% annual carrying charge rate and existing plans, the B/C for the reference and 20% Wind scenarios are roughly 1.4 and 1.0, respectively. Economic plans show the need for thousands of miles of 765 kv AC in either scenario, with 2 or 7 very long, high capacity 800 kv DC lines depending upon the scenario. The reference scenario shows the need for a 765 kv line from LaCygne, KS across MO and IL to AEP at Sullivan, IN, as well as a double circuit 500 kv from Ft Smith AR to Entergy ANO & Dell to TVA and SoCo. For the 20% Wind 1 Dockets or cases with no significant activity during this period have been omitted. 17 of 68

34 scenario, 3 of the 800 kv HVDC lines are sourced from the SPP 765 kv Overlay and another 800 kv HVDC line is sourced on the Nebraska/Iowa border near Omaha. Final iteration on optimizing 2024 expansion plans in process. Reliability assessments for 2018 reliability and 2024 economic models are in process. Expect economic and reliability analyses to be completed in next few weeks with results published by year end. Scope for JCSP for is under development and is expected to include a 10% National RPS future, as well as other futures to support carbon restrictions, increased nuclear expansion, etc. DOE seems to be expecting JCSP to take over congestion studies for the Eastern Interconnection. C. Waiver Requests Three waiver requests were received in the second quarter from KEPCo, KPP and NTEC. At its July 15-16, 2008 meeting, the Markets and Operations Policy Committee (MOPC) unanimously approved the waivers and requested that the updated values be included in the recommendations submitted for Board of Directors approval. The Board of Directors approved the waiver requests at its July 29, 2008 meeting. Two new waiver requests, Westar and City of Coffeyville, were received during the third quarter and were discussed at the MOPC s October 14-15, 2008 Meeting. Both waivers were endorsed by MOPC. 1. Westar Waiver Request On September 15, 2008, 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 Westar Energy, Inc. (Westar) for new Designated Resources of 99 MW from the Central Plains wind farm located in Wichita, Kansas, based on the upgrade costs associated with transmission from this resource. SPP s 120-day deadline under Attachment J is January 13, Westar requested a waiver based upon Section III.C.2. i and ii of Attachment J for reconsideration on the basis that the request is a 10-year reservation and a wind resource. This waiver request was discussed at the regular September meeting of the Cost Allocation Working Group (CAWG). A special teleconference was held on October 9, Based on the discussion and action of the CAWG during the special meeting, the CAWG is recommending that the SPP Regional State Committee (RSC) recommend to the SPP Board of Directors to approve to increase the funding of the waiver in accordance with the RSC-approved new policy for the direct assignment portion for the wind resources. This would approve 67% of the upgrade cost to be regionally funded and 33% to be directly assigned to Westar. The recommendation of SPP staff is to provide additional Base Plan funding of $38,981 based on the 10-year reservation and existing tariff provisions. SPP staff acknowledges that a policy revision has been approved by the CAWG/RSC and if that policy revision is ultimately approved by through the SPP/FERC process, the resulting recommendation would be altered accordingly. 2. City of Coffeyville Waiver Request 2 18 of 68

35 On September 11, 2008, 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 the City of Coffeyville (CMLP) for new Designated Resources for a profiled reservation request of 16 MW beginning in 2008 and growing to 197 MW in 2042 for the City, based on the upgrade costs associated with transmission from this resource. SPP s 120-day deadline under Attachment J is January 9, CMLP requested a waiver based upon Section III.C.2. i and ii of Attachment J for reconsideration based on that the request is a 34-year reservation. This waiver request was discussed in the regular September meeting of the CAWG. A special teleconference was held on October 9, Based on the discussion and action of the CAWG during the special meeting, the CAWG is recommending that the SPP RSC recommend to the SPP Board of Directors to approve the full funding of the waiver for the SPP jurisdictional upgrades. This will specifically exclude the required upgrades that are owned by the City of Coffeyville. The recommendation of SPP staff is to approve the waiver request to fully fund the projects excluding the CMLP-owned direct assignment upgrades, based on the 34-year reservation and realizing that the anticipated Safe Harbor limit using 91 MW would allow full funding of the project with the exclusion of the CMLP-owned direct assignment upgrades. D. Approval of Membership Agreement Amendments & the First Set of Tariff Revisions to Allow Three Nebraska Utilities to Join SPP At its September 8, 2008 Special Meeting, the SPP Board of Directors approved amendments to the SPP Membership Agreement to accommodate provisions of the Nebraska Public Power District (NPPD) and Omaha Public Power District (OPPD) as state power agencies and for Lincoln Energy System (LES) as a municipal utility to join SPP. The first of two sets of Tariff revisions necessary to allow the Nebraska entities to begin operation in SPP were also approved. These revisions were filed with the Commission on September 30, 2008 in Docket No. ER The second set of Tariff revisions is expected to be submitted for review and approval at the October 2008 meetings of the MOPC and the SPP Board of Directors. E. Balanced Economic Portfolio (Docket No. ER ) On August 15, 2008, after sixteen months of collaborative efforts by the RSC and the CAWG, SPP filed amendments to the SPP Tariff to establish a process for including a balanced portfolio of economic upgrades into the SPP Transmission Expansion Plan (STEP) and a regional postage stamp rate design for recovery of the costs of such upgrades. SPP also proposes to amend the Tariff provisions relating to the treatment of upgrades that result in the deferral or displacement of other upgrades. An effective date of October 17, 2008 was requested. Four parties filed Comments, all of which expressed support for the Balanced Economic Portfolio initiative of 68

36 On October 16, 2008, FERC unanimously voted to approve SPP s filing, and issued an Order Accepting Tariff Revisions, as Modified. SPP must submit a compliance filing by December 15, 2008, with provisions ensuring that system design software results needed for stakeholders to verify the application of the assumptions in creating the adjusted production cost-benefit metrics will be made available, and clarifying that costs incurred by transmission owners or zones due to third-party impacts are included among the factors affecting the revenue requirement associated with the economic upgrade, as discussed in the Order. F. SPP Petition of Waiver of the Commission s Regulations under RT04-1 On September 3, 2008, FERC granted SPP s May 19, 2008 petition of waiver of the Commission s regulations requiring SPP to perform an audit of the independence of its decision-making process as an RTO. G. FERC Audits 1. Docket No. PA08-2: RE & RTO Audit On October 4, 2007, FERC initiated an audit concerning SPP s responsibilities as a Regional Entity (RE) and an RTO. FERC seeks to determine whether SPP is operating in compliance with the SPP Bylaws, Delegation Agreement between NERC and SPP and the conditions included in the Delegation Order, SPP Membership Agreement, transmission provider obligations described in the SPP OATT and other obligations and responsibilities as approved by the Commission. SPP has responded to multiple data requests, phone interviews and requests, and FERC has conducted one site visit to date, with more anticipated. On September 8, 2008, FERC issued a draft audit report regarding the audit of the Regional Entity. On October 10, 2008, SPP filed its response to the draft audit report. A meeting with FERC is scheduled for October 31, 2008, to discuss the findings. 2. Docket No. PA08-16: SPP OASIS Audit By letter dated March 28, 2008, FERC announced that it is commencing an audit to determine whether the information posted on SPP s OASIS is consistent with the requirements of 18 C.F.R. Section 37.6, with primary focus on the modifications from Order No The audit will cover March 17, 2008 to the present. To date, SPP has participated in one phone interview and provided written responses to inquiries. On August 22, 2008, FERC completed an audit of SPP for the period of March 17, 2008 through April 30, 2008, and issued a letter order approving the recommended corrective actions. In this order, SPP was required to make quarterly filings (no later than 30 days after end of a calendar quarter) until all corrective actions are complete. SPP has completed implementation of all correction actions and is preparing a filing to indicate completion of corrective actions implementation of 68

37 H. FERC CEII Requests Since the close of the second quarter, SPP has received 42 requests for Critical Energy Infrastructure Information (CEII) through the FERC process. SPP also continues to receive a large number of SPP map and model requests through SPP s internal processes. SPP staff is currently awaiting FERC s determination on 41 CEII requests. 2 I. FERC Rulemaking Proceedings 1. Docket No. RM05-5/RM96-1: Standards Governing Business Practices and Electronic Communications for Public Utilities Developed through Consensus by the Wholesale Electric Quadrant (WEQ) of the North American Energy Standards Board (NAESB) On July 21, 2008, FERC issued Order No. 676-C, which became effective August 28, Paragraph 80 of the Order provides, The standards incorporated by reference in this Final Rule must be implemented by October 1, 2008, with the following exceptions: (1) The reliability related standards (WEQ-004 Coordinate Interchange, WEQ-005 Area Control Error (ACE) Equation Special Cases, WEQ-006 Manual Time Error, WEQ-007 Inadvertent Interchange Payback, and WEQ-008 Transmission Loading Relief - Eastern Interconnection) are required to be implemented by the later of the effective date of the Final Rule in RM or the effective date of this Final Rule [August 28, 2008]; (2) WEQ-001 OASIS Standards are required to be implemented by January 31, 2009; and (3) Appendix D to the WEQ-008 Transmission Loading Relief - Eastern Interconnection standards need not be implemented until NERC completes the field testing. On September 17, 2008, FERC granted rehearing of the July 21, 2008 Order. 2. Docket Nos. RM05-17 & RM05-25: Order Nos. 890, 890-A & 890-B a. Order No. 890-A Pursuant to Paragraph 592 of Order No. 890-A, transmission providers have until July 14, 2008 to develop, in coordination with NERC and NAESB, a consistent set of tracking capabilities and business practices for tagging for implementation of conditional firm service. On July 8, 2008, FERC granted NAESB s July 7, 2008 request to extend from July 14, 2008 to August 29, 2008 the time transmission providers, working through NAESB and 2 Docket Nos. CE08-78, CE08-82, CE08-86, CE08-88, CE08-89, CE08-112, CE08-114, CE08-138, CE08-140, CE08-165, CE08-174, CE08-176, CE08-180, CE08-186, CE08-195, CE08-196, CE08-198, CE08-204, CE08-206, CE08-209, CE08-213, CE08-215, CE08-218, CE08-223, CE08-228, CE08-229, CE08-239, CE08-243, CE08-260, CE08-262, CE08-268, CE08-273, CE08-276, CE08-277, CE08-278, CE08-279, CE08-280, CE08-282, CE08-289, CE and CE of 68

38 NERC, have to develop a consistent set of tracking capabilities and business practices for tagging for implementation of conditional firm service, as required in Order No A. b. Order No. 890-B On June 23, 2008, the Commission issued Order No. 890-B affirming its basic determinations in Order Nos. 890 and 890-A, granting rehearing and clarification of certain revisions to its regulations and the pro-forma OATT adopted in Order Nos. 888 and 889. Order No. 890-B addresses several key issues, such as the methodology for calculating ATC, the standardization of energy and generation imbalance charges, rollover rights, rules regarding the designation and undesignation of network resources, and the reporting of transmission capacity reassignments in the Electric Quarterly Reports (EQR). Order No. 890-B became effective September 8, RTO and ISO transmission providers, transmission providers whose facilities are in the footprint of an RTO or ISO, and WSPP must submit an FPA section 206 filing that contains the revised non-rate terms and conditions of the pro forma OATT as stated in Appendix B by October 6, On August 22, 2008, FERC issued an Order Granting Rehearing for Further Consideration regarding the June 23, 2008 Order. On October 6, 2008 under Docket OA09-5, SPP submitted Tariff revisions incorporating specific changes to the Order 890 pro forma OATT adopted by FERC in Order 890-B. An effective date of October 6, 2008 is requested. SPP states that its EIS Market is consistent with or superior to the pro forma Schedules 4 and 9, and declines to incorporate the revisions adopted by the Order 890-B for Schedules 4 and 9. In the May 16, 2008 Order in Docket OA08-5, the Commission concluded "that SPP's imbalance market is consistent with the Order No. 890 pro forma OATT. Accordingly, we will not require SPP to file revisions in its OATT to include the revisions to Schedule 4 and the new Schedule 9 adopted in Order No c. Order No. 890 On September 12, 2008, FERC granted an extension of time to and including February 6, 2009 for SPP to comply with the July 11, 2008 Order issued in Docket OA This is regarding the Attachment O Revisions for Coordinated and Regional Planning Process. 3. Docket No. RM05-30: Rules on ERO Certification and Procedures for the Establishment, Approval and Enforcement of Mandatory Electric Reliability Standards On April 17, 2008, FERC issued a Statement of Administrative Policy on Processing Reliability Notices of Penalty and Order Revising Statement in Order No of 68

39 Any settlement of an alleged violation filed by the Electric Reliability Organization (ERO) after April 17, 2008 will be subject to Commission review pursuant to section 39.7(e) of the Commission s regulations. 4. Docket Nos. RM06-16 and RM06-22: Eight New Mandatory Critical Infrastructure Protection (CIP) Reliability Standards On July 30, 2008, NERC submitted a supplemental compliance filing in Docket RM06-16 in response to Paragraph 751 and 757 of Order 706. On August 13, 2008, FERC accepted NERC s May 16, 2008 compliance filing in Docket RM On August 14, 2008, NERC submitted a further compliance filing in response to Paragraph 18 of the February 21, 2008 Order under RM On September 18, 2008, FERC issued an Order on Proposed Clarification under RM The Commission is proposing to clarify that the facilities within a nuclear generation plant in the United States that are not regulated by the United States Nuclear Regulatory Commission are subject to compliance with the eight mandatory CIP Reliability Standards approved in Order No On September 18, 2008, FERC issued a notice seeking public comment on its proposal to close the Cyber Security Gap under RM Comments are due October 20, Docket No. RM06-23: Order No. 702 CEII Regulations Rehearing of Order No. 702, which amends Commission regulations for gaining access to CEII, was granted on December 31, 2007 per the request of the EEI and has not yet been acted on by the Commission. 6. Docket No. RM07-3: Order No. 705 Three New NERC Reliability Standards On April 1, 2008, NERC made a compliance filing in response to paragraph 135 of Order No This filing was approved by the Commission on May 29, On June 2, 2008, the Commission granted the ISO/RTO Council s January 28, 2008 request for clarification and denied the alternative request for rehearing of Order No Docket Nos. RM07-19/AD07-7: Wholesale Competition in Regions with Organized Electric Markets On April 21, 2008, SPP submitted comments on the February 22, 2008 NOPR. In its comments, SPP lends support to the Commission s goal of providing greater use of demand resources, proposes that RTOs and ISOs host bulletin board for postings to be made by willing buyers and sellers with these buyers and sellers bearing the responsibility for all content posted, suggests that the proposals regarding Market Monitoring Polices are consistent with FERC s Order in Docket No. ER04-1 (SPP RTO Order) and asserts that SPP s current structure complies with the proposals set forth in the NOPR of 68

40 On October 17, 2008, FERC issued a Final Rule in Order 719. SPP staff is in process of reviewing this order and determining its implications to SPP. 8. Docket No. RM08-3: Proposed Reliability Standard for Nuclear Plant Interface Coordination (NUC-001-1) On May 13, 2008, the ISO/RTO Council filed comments on the proposed Reliability Standard NUC (Nuclear Plant Interface Coordination) which would mandate coordination between Nuclear Plant Generator Operators and Transmission Entities, and on the definitions proposed by NERC to supplement NUC Commission action on these, and other comments received, is forthcoming. 9. Docket No. RM08-7: Modification of Interchange and Transmission Loading Relief Reliability Standards and Electric Reliability Organization Interpretation of Specific Requirements of Four Reliability Standards On July 21, 2008, FERC issued final rule in Order No FERC made improvements to grid reliability by modifying five Reliability Standards, approved in 2007, related to interchange scheduling and coordination and approved NERC s interpretation of five specific requirements of Commission-approved reliability standards. FERC also is asking for explanation on a sixth modified standard related to transmission load relief (TLR). J. FERC Administrative Proceedings 1. Docket No. AD08-2: SPP Status Report Improvement of Interconnection Queuing Practices On March 20, 2008, the Commission issued an Order on Technical Conference directing that each RTO and Independent System Operator (ISO) file a status report with the Commission regarding their efforts to improve the processing of their interconnection queues. On April 21, 2008, SPP submitted a Status Report in response to the Order on Technical Conference issued March 20, SPP continues to experience an unexpected and unprecedented level of activity in its generation interconnection queue. A record number of requests are presently being processed and a record number of requests are expected to be received in calendar year Docket No. AD08-7: Notice of Inquiry (NOI) - Annual Charges Assessment for Public Utilities On April 21, 2008, FERC issued a NOI seeking comments on whether its current methodology for assessing electric annual charges to public utilities remains fair and equitable, as well as alternative methodologies of 68

41 The ISO/RTO Council filed Joint Comments on May 28, 2008 and Joint Reply Comments on July 3, 2008, requesting that FERC reevaluate its annual charge regulations and adopt a methodology that mitigates the discriminatory impacts associated with the current methodology. The ISO/RTO Council contends, among other things, that FERC can reform its present methodology to eliminate undue discrimination without assessing Wholesale Power Sales and that reliability program costs are properly assessed to all users, owners, and operators of the grid. 3. Docket No. AD08-9: Review of Wholesale Electricity Markets On July 1, 2008, FERC hosted a conference to review the state of regional wholesale electricity markets. SPP President and CEO Nick Brown and Richard Dillon, SPP Director of Market Development and Analysis, participated on behalf of the SPP RTO. Presentation materials from this conference are available in the FERC Online elibrary. K. FERC ERO Rules & Organizational Filings Docket No. RR06-1: NERC Filing of Version 5 Reliability Standards; Docket No. RR06-3: 2007 Business Plan and Budget, & Budgets of Regional Entities; & Docket Nos. RR07-1 thru RR07-8: Regional Entity Delegation Agreements 3 On April 7, 2008, NERC filed Executed Amended and Restated Delegation Agreements in these dockets pursuant to the Commission s March 21, 2008 Order. On April 21, 2008, NERC filed a request for rehearing of the Commission s March 21, 2008 Order in which FERC accepted NERC s October 30, 2007 compliance filing and conditionally accepted NERC s November 2, 2007 filing of proposed revisions to the Western Electricity Coordinating Council (WECC) bylaws, the latter of which is to become effective conditioned on subsequent membership approval. On May 1, 2008, NERC submitted its quarterly report in Docket No. RR regarding the analysis of reliability standards voting results for the period of January through March, On May 19, 2008, NERC submitted a compliance filing containing the NERC and Northeast Power Coordinating Council, Inc. (NPCC) response to P 174 of the Commission s March 21, 2008 Order in Docket No. RR et al.; and (2) the NERC and the Florida Reliability Coordinating Council (FRCC) response to P 252 of the March 21 Order. 3 Due to the overlap in content, these dockets are being presented together of 68

42 On May 21, 2008, the Commission granted rehearing of its March 21, 2008 Order. On July 15, 2008, the Commission accepted NERC's uncontested May 19, 2008 filing as meeting the 60-day submission requirements ordered by the Commission. FERC will review the proposed revisions for compliance with the Commission s directives when they are actually filed as part of the 120-day compliance filing, due on or before July 21, NERC has been granted an extension of time up to and including July 21, 2008 to comply with the Commission s June 17, 2008 and March 21, 2008 Orders. SPP Delegation Agreement Revisions are addressed at paragraphs of the March 21, 2008 Order: SPP must revise its bylaws to explicitly state that membership in the Regional Entity is open to any entity and that SPP will not charge a fee for such participation. At P 213. NERC and SPP must, either revise section 5 of Exhibit E to include a list of SPP s specific procedures for ensuring that non-statutory funding will be kept separate from funding for statutory activities, or...provide further explanation demonstrating that SPP s current proposal will accomplish what is required. At P 216. On July 21, 2008, NERC submitted its compliance filing pursuant to the Commission s March 21, 2008 Order in Docket Nos. RR and RR through RR NERC s compliance filing consists of a revised Amended and Restated Pro Forma Delegation Agreement with the Regional Entities, a revised NERC Compliance Monitoring and Enforcement Program document (including revised Attachment 2, Hearing Procedures), revised Amended and Restated Delegation Agreements with each of the Regional Entities, and revisions to the NERC Rules of Procedure in compliance with the March 21, 2008 Order. On August 8, 2008 in Docket ER , SPP submitted a filing to revise its bylaws according to the March 21 Order. On October 6, 2008, FERC issued a letter order. The changes are conditionally accepted in part, and rejected in part, as noted in the order and are effective May 18, 2007 and April 5, 2008, consistent with previous Commission orders. SPP must file, within 30 days of the date of this order, a filing correcting several items. SPP s compliance filing is due November 5, On September 15, 2008, NERC submitted supplemental information adding language in the second paragraph of the CMEP following the existing third sentence. L. FERC Electric Rate Filing & Other Formal Filings of Interest 1. Docket Nos. EL & ER : Settlement concerning PJM s Reliability Pricing Model (RPM) Program of 68

43 On July 18, 2008, FERC issued an order conditionally accepting PJM s May 20, 2008 Compliance Filing concerning the use of avoided cost rates for default bids in PJM s RPM program. PJM must submit a further compliance filing by August 18, On August 18, 2008, PJM submitted a compliance filing pursuant to the July 18 Order. Specifically, PJM incorporated the revised language in Section 6.7 of the Tariff requiring the Capacity Market Seller to provide additional information in the sworn, notarized statement that it must provide to PJM with its request to apply the Section 6.7(c) retirement Avoidable Cost Rate. PJM also revised the Tariff to state that PJM must publish the number of Generation Capacity Resources and the number of megawatts per Locational Deliverability Area that use the retirement default rates. Comments on this filing were due September 8, None were filed. On September 18, 2008, FERC issued a press release stating it granted a request for technical conference related to PJM s ongoing review of the RPM and directed PJM to submit a report to the Commission by December 15, 2008, detailing its findings and the actions it proposes to take, including filing proposals as necessary to implement changes to RPM. The related order was issued on September 19, FERC dismissed a complaint by RPM Buyers that RPM had not resulted in just and reasonable capacity prices during the transition period between PJM s prior capacity market mechanism and full implementation of RPM. 2. Docket No. EL07-73/ER07-319: SPP Energy Imbalance Service (EIS) Market Compliance Filing Violation Relaxation Limits (VRLs) On May 21, 2008, SPP filed notice with the Commission that the active parties have initiated discussions, with the assistance of the Commission s Dispute Resolution Service, to resolve the issues raised in the Commission s June 29, 2007 Order instituting paper hearing procedures to consider the justness and reasonableness of SPP s use of VRLs related to SPP s EIS Market. The paper hearing procedures established in the June 29, 2007 Order directed SPP to submit additional information concerning the VRL mechanism, including, among other things, the methodology used to determine VRL values and an explanation addressing the operation of VRLs in the context of SPP's dispatch process and mitigation rules. The June 29, 2007 Order indicated FERC s expectation that a decision would be issued on or before June 29, However, it is requested that the Commission withhold issuance of an order in this proceeding to allow additional time for negotiations. On July 29, 2008, SPP submitted a status report pursuant to the June 29, 2007 Order. On September 26, 2008, SPP submitted a status report pursuant to the June 29, 2007 Order. SPP, on behalf of the active parties, will provide a further status report by November 1, 2008 regarding the status of these negotiations and will promptly notify the Commission if the active parties elect to terminate the ADR process. 3. Docket No. EL08-31: Westar s Petition for a Declaratory Order to Confirm Incentive Rate Treatment for High Voltage Transmission Projects of 68

44 On December 28, 2007, Westar filed a petition for a declaratory order approving the transmission rate incentives for three new high voltage transmission facilities in Westar s service territory. The proposed rate incentives are for two new 345 kv transmission lines, as well as a recently installed 345/230 kv transformer. SPP intervened in this proceeding on January 15, On March 24, 2008, FERC issued an order in Docket Nos. EL and ER granting, in part, and denying, in part, Westar s December 28, 2007 Petition for a Declaratory Order. The Commission also accepted, in part, and denied, in part, Westar s proposed revisions to its formula rate, in Docket No. ER subject to a nominal suspension and conditions, to become effective June 1, 2008, subject to refund, and hearing and settlement judge procedures. On September 26, 2008, Westar Energy submitted a settlement offer. Also on September 26, SPP and Westar submitted a Motion for Interim Rate Relief and Request for Expedited Action, requesting the Commission to act no later than October 10, On September 29, 2008, the Order of Chief Judge Shortening Time to Respond and Motion for Interim Rate Relief was issued. Time to respond was shortened to and including September 30, On October 1, 2008, the Order of Chief Judge Granting Motion for Interim Rate Relief was issued. The order states, Westar is hereby authorized, pursuant to section 35.1(e) of the Commission s regulations, 18 C.F.R. 35.1(e) (2007), to institute the interim rates to become effective on October 1, In the event the Commission does not approve the Settlement Agreement, Westar and SPP have the right to reinstate the ER Rates and to implement credits or offsets through the true-up process under the protocols accepted by the Commission in Docket No. ER Docket No. EL08-59: ConocoPhillips Complaint against Entergy Services, Inc. (Entergy) On April 24, 2008, ConocoPhillips filed a complaint against Entergy, alleging that Entergy violated its OATT and Commission policy by terminating two firm transmission service reservations. Entergy filed an Answer on May 14, 2008, stating that the agreements were terminated because the transmission system became oversubscribed and that the request should not have been granted. SPP moved to intervene in this proceeding on May 14, On June 2, 2008, SPP filed a Limited Response, stating that the reservations would not have been granted if the software had functioned properly and that the ICT s decision to terminate reservations was driven by real-time reliability concerns. On July 24, 2008, FERC granted relief requested by Conoco in part. FERC finds that the termination of Conoco s confirmed, firm transmission service was improper. NRG of 68

45 Companies requests that the Commission investigate the cause of Entergy s software error and the alleged continued overselling and increased curtailments at the Entergy- Ameren interface are denied. On August 25, 2008, SPP filed a Request for Rehearing. SPP specifically states that it considered all alternatives following the oversell of capacity on the Ameren interface, including offering customers the right to terminate all or any portion of their transmission reservations. Only as a last resort did SPP implement the annulment of those reservations that were improperly granted due to software error. On August 25, 2008, Entergy filed a Request for Rehearing or Clarification. On September 8, 2008, Conoco filed a Request for Leave to File Answer, and Answer. On September 23, 2008, Entergy files an Answer requesting Commission to grant rehearing or clarification of the July 24, 2008 Order. On September 24, 2008, FERC issued an Order Granting Rehearing for Further Consideration. 5. Docket Nos. ER03-765, ER & ER08-807: Proposed Revisions to Schedule 2 of the SPP OATT - Reactive Compensation On April 8, 2008, SPP filed proposed revisions to Schedule 2 of SPP s Tariff. The proposed revisions serve to: (1) reincorporate language providing for the recognition by SPP of new generators as Qualified Generators (QGs) throughout the year; (2) clarify that new generators must apply to SPP for QG status; and (3) clarify that QGs will be compensated for providing reactive power at the beginning of the first month after SPP acceptance of the generation owner s application. FERC accepted SPP s April 8, 2008 filing by letter order on June 4, An effective date of March 1, 2007 was granted for revision number one, above. An effective date of June 7, 2008 was granted for the remaining revisions. On September 19, 2008, AEP filed a Petition for Review with the United States Court of Appeals fir the District of Columbia Circuit. The Petition for Review relates to the orders issued by the Commission on November 19, 2007, and August 28, 2008, in Docket ER Docket Nos. ER06-20 & EC06-4: Independent Transmission Operator (ITO) Semi-Annual Report The semi-annual report is required by FERC s orders approving the establishment of the ITO and section of the ITO Agreement in LG&E/KU s Tariff. On September 26, 2008, SPP, as the ITO for the LG&E and KU systems, submitted the ITO Semi-Annual Report. This covers the period of March 1, 2008 through August 31, Docket Nos. ER06-451, et al.: SPP EIS Market Implementation of 68

46 On August 13, 2008 in Docket ER06-451, SPP filed an informational status report concerning its incorporation of demand-side resources into its EIS Market. On September 23, 2008, SPP submitted to FERC a compliance filing in Docket No. ER containing revised tariff sheets relating to the Energy Imbalance Market. Specifically, the May 21 Filing revised SPP's OATT provisions allowing external resources to participate in SPP's real-time energy imbalance service market. SPP submits revisions to Section 2(j) and 2(m) of Attachment AO to more closely paraphrase the language of the April 21 Order. On October 17, 2008, FERC issued a letter order accepting the May 21 and September 23 compliance filings, effective on or before February 1, 2009, upon notice by SPP, as requested. 8. Docket No. ER : AEP Filing of Revised Pro-forma Tariff Sheets to Update AEP s Transmission Service Rates & Institute a Formula Rate On May 27, 2008, AEP filed its Notice of Annual Update of AEP Formula Rate. Settlement conferences were held on April 23, May 8, and June 12, Several proposals have been exchanged, the latest having been made on June 17, This proposal was discussed in a conference call on June 18, 2008 and is still under consideration. According to the Report to the Commission and Chief Judge issued on August 28, 2008, the parties exchanged drafts of settlement proposals on August 27, On September 17, 2008, SPP submitted changes to Pricing Zone Rates intended to implement a rate change for PSO and SWEPCO. An effective date of February 1, 2008 is requested. See docket No. ER Docket No. ER08-281: Oklahoma Gas & Electric Company (OG&E) Formula Rate Case On April 24, 2008, the Commission issued a letter order accepting OG&E s March 3, 2008 Formula Rate compliance filing. Settlement conferences were held on July 8 and August 20, The September 26, 2008 settlement conference was cancelled. It will be rescheduled. On October 17, 2008, SPP made a ministerial filing to incorporate the rates into SPP s OATT. An effective date of July 1, 2008 is requested. A separate docket number will be assigned. 10. Docket No. ER08-313: Southwestern Public Service Company (SPS) Formula Rate Case (Consolidated with the following NITSA filings: ER08-923, ER , ER , ER , ER , ER ) On July 2, 2008, the Commission issued an order consolidating Docket Nos. ER and ER (SPP moved to intervene out-of-time in this proceeding on January 11, 2008.) of 68

47 The Commission suspended the Network Integration Transmission Service Agreements between SPS and two SPS network customers, Golden Spread Electric Cooperative, Inc. and South Plains Electric Cooperative, Inc. FERC also accepted the proposed revised Agreements for filing, suspended them for a nominal period, made them effective July 6, 2008, as requested, subject to refund, and set the issues raised for hearing and settlement judge procedures. On July 25, 2008 in Docket No. ER , SPP filed with FERC an executed Service Agreement for Network Integration Transmission Service between SPP as Transmission Provider and Southwestern Public Service Company as Network Customer, as well as an executed Network Operating Agreement between SPP as Transmission Provider and SPS as both Network Customer and Host Transmission Owner. SPP Service Agreement No. First Revised An effective date of July 6, 2008 is requested. This agreement replaces SA No filed in EQR only. On July 25, 2008 in Docket ER , SPP filed with FERC an executed Service Agreement for Network Integration Transmission Service between SPP as Transmission Provider and Southwestern Public Service Company as Network Customer, as well as an executed Network Operating Agreement between SPP as Transmission Provider and SPS as both Network Customer and Host Transmission Owner. SPP Service Agreement No. Second Revised 543. An effective date of July 6, 2008 is requested. This agreement supersedes the agreement filed in ER On August 1, 2008, Golden Spread Electric Cooperative, Inc. filed a Request for Rehearing. On August 15, 2008, Golden Spread filed a Motion to Intervene, Protest and Motion to Summarily Reject Filing, in the Alternative, Motion to Consolidate. On August 5, 2008 in Docket No. ER , SPP filed with FERC a partially executed Service Agreement for Network Integration Transmission Service between SPP as Transmission Provider and Golden Spread Electric Cooperative, Inc. as Network Customer, as well as a partially executed Network Operating Agreement between SPP as Transmission Provider, Golden Spread as Network Customer and Southwestern Public Service Company as Host Transmission Owner. SPP Service Agreement No. First Revised An effective date of July 6, 2008 is requested. This agreement replaces SA No filed in EQR only. On August 5, 2008 in Docket No. ER , SPP filed with FERC an executed Service Agreement for Network Integration Transmission Service between SPP as Transmission Provider and Southwestern Public Service Company as Network Customer, as well as a partially executed Network Operating Agreement between SPP as Transmission Provider and SPS as both Network Customer and Host Transmission Owner. SPP Service Agreement No. First Revised An effective date of July 6, 2008 is requested. This agreement supersedes the agreement filed in ER On August 5, 2008 in Docket No. ER , SPP filed with FERC an executed Service Agreement for Network Integration Transmission Service between SPP as Transmission Provider and Southwestern Public Service Company as Network Customer, as well as a partially executed Network Operating Agreement between SPP as Transmission Provider and SPS as both Network Customer and Host Transmission Owner. SPP of 68

48 Service Agreement Number First Revised An effective date of July 6, 2008 is requested. This agreement supersedes the agreement filed in ER A formal settlement conference was held on August 21, On September 2, 2008, FERC issued an order Granting Rehearing for Further Consideration in ER On September 2, 2008 Southwest Power Pool, Inc. submitted to FERC an Answer To Protests and Requests For Rejection in Docket No. ER On September 5, 2008, Southwest Power Pool, Inc. submitted to FERC an Answer To Protests And Requests For Rejection under Docket No. ER On September 10, 2008, Southwest Power Pool, Inc. submitted to FERC an Answer To Protest And Request For Rejection in Docket No. ER , ER and ER On September 23, 2008, FERC issued an Order accepting and suspending the service agreement and consolidating the ER and ER proceedings with ER and ER (an existing SPS Formula Rate proceeding). On September 30, 2008, Xcel Energy Service, on behalf of Southwestern Public Service Company submitted an informational filing explaining SPS efforts to determine which of its facilities are transmission facilities, and the applicable transmission service rates as required by Attachment AI to the SPP OATT. On October 1, 2008, FERC issued a letter order "Consolidating Dockets, Accepting and Suspending Service Agreements, and Establishing Hearing and Settlement Judge Procedures." In this order, FERC consolidated dockets ER , ER , and ER , along with ER08-313, ER08-923, ER , ER Docket No. ER08-396: Westar Formula Rate Case Rates Effective June 1, 2008 On September 26, 2008, Westar Energy submitted a settlement offer. Also on September 26, SPP and Westar submitted a Motion for Interim Rate Relief and Request for Expedited Action, requesting the Commission to act no later than October 10, On September 29, 2008, the Order of Chief Judge Shortening Time to Respond and Motion for Interim Rate Relief was issued. Time to respond was shortened to and including September 30, On October 1, 2008, the Order of Chief Judge Granting Motion for Interim Rate Relief was issued. The order states, Westar is hereby authorized, pursuant to section 35.1(e) of the Commission s regulations, 18 C.F.R. 35.1(e) (2007), to institute the interim rates to become effective on October 1, In the event the Commission does not approve the Settlement Agreement, Westar and SPP have the right to reinstate the ER Rates and to implement credits or offsets through the true-up process under the protocols accepted by the Commission in Docket No. ER of 68

49 12. Docket No. ER08-513: Entergy s Filing of Proposed Revisions to Attachment V Weekly Procurement Process On May 5, 2008, the Commission issued an order conditionally accepting and suspending amendments to Entergy s Weekly Procurement Process for five months, to become effective October 11, 2008 or on an earlier date, subject to refund and subject to a further order on the proposed tariff revisions directed to be filed in the order. The Commission stated that it will consider allowing an effective date earlier than October 11, 2008, if the ICT agrees that the model is ready and Entergy files the required tariff revisions no later than 60 days before that date. On August 29, 2008, Entergy submitted proposed revisions to Attachment V of its OATT. On October 10, 2008, FERC issued a letter order accepting the August 29, 2008 filing, effective October 10, Entergy is directed to file a Software Development Progress Report by January 11, 2009, if the Weekly Procurement Process implementation filing is not made by then. 13. Docket No. ER08-572: Entergy s Filing of Amendments to the ICT Agreement and a Revision to Section 10.2 of Entergy s OATT On April 15, 2008, the Commission accepted amendments proposed by Entergy to the ICT Agreement and Entergy s OATT. Entergy was directed to submit a compliance filing by May 15, On May 15, 2008, SPP filed a request for rehearing of the April 15 Order. The Commission granted the rehearing on June 16, On May 15, 2008, Entergy submitted amendments to Section 3.8 of the ICT Agreement in compliance with the April 15 Order to reflect that the incremental full-time employees [of the ICT] are not restricted to performing tasks related to FERC Order Nos. 890 and 693 and related OATT provisions. An effective date of May 16, 2008 is requested. The ICT concurs with these amendments. On July 25, 2008, FERC accepts Entergy s May 15, 2008 compliance filing. This order constitutes final agency action on the specific matter of the increase of staff in the ICT Agreement. On August 4, 2008, FERC issued an order accepting Entergy s proposed amendment to the ICT Agreement and dismissing SPP s request for rehearing as moot. 14. Docket No. ER08-746: SPP Proposed Tariff Revisions - Aggregate Study, Revenue Crediting, and Cost Allocation Procedures On March 28, 2008, SPP submitted proposed Tariff revisions in order to: (a) modify its transmission service revenue crediting processes; (b) clarify the application of its network upgrade cost allocation methodology; (c) modify the format of certain of 68

50 attachments to its Tariff; (d) identify a new type of network upgrade; and (e) incorporate various miscellaneous clarifications. SPP requests an effective date of May 27, On May 5, 2008, SPP filed an Answer to Comments and Conditional Protest. On May 27, 2008, the Commission issued an order accepting in part and rejecting in part SPP s Tariff revisions, to become effective May 27, 2008, as requested. On June 25, 2008, in response to the May 27, 2008 Order, SPP submitted a compliance filing revising Sections 34.1, 1.9(b), 1.50, 32.11, and Article I of Attachment Z2 (Revenue Crediting for Upgrades) to clarify how zonal point-to-point transmission service revenue is accounted for when SPP calculates the network monthly demand charges for SPP s transmission owners with different accounting practices. An effective date of May 27, 2008 is requested. On July 18, 2008, SPP submitted an amendatory filing to correct a clerical error in proposed Section 34.1 of the Aggregate Study compliance filing made June 25, 2008 filing. Comments on SPP s filing were due August 8, On August 28, 2008, FERC accepted the compliance filing in ER clarifying how zonal point-to-point transmission service revenue is accounted for when SPP calculates the network monthly demand charges for SPP's transmission owners with different accounting practices, with an effective date of May 27, This order constitutes final agency action. 15. Docket No. ER08-777: Westar Formula Rate Revisions Effective June 1, 2008 On April 1, 2008, Westar submitted revisions to its Formula Rate, as set forth in Attachment H-1 to Westar s OATT, to provide for the recovery of operation and maintenance (O&M) expenses incurred to repair and restore its transmission system after severe property damage caused by ice storms in December SPP moved to intervene in this proceeding on April 22, On May 29, 2008, the Commission conditionally accepted revisions to Westar s Formula Rate, to become effective June 1, 2008, as requested. Westar submitted the required compliance filing on June 13, On July 7, 2008, KEPCO filed Comments requesting clarifications to be made to tariff sheets. On August 28, 2008, FERC issued an order conditionally accepting compliance filing, effective June 1, Westar was directed to submit a compliance filing with 15 days. Westar must include a note in its tariff either stating that all future storm damage reserves are subtracted from rate base until they are applied to offset transmission property damage expenses or indicating that the reserves are placed in an external escrow account with the earnings accruing to the reserves booked to Account On September 12, 2008, Westar submitted its compliance filing pursuant to the August 28, 2008 Order of 68

51 16. Docket Nos. ER & ER08-913: Congestion Management Process Revisions On July 24, 2007, the Commission issued an order conditionally accepting revisions to MISO s and PJM s Congestion Management Process (CMP) to change the market flow threshold used to assign NERC Transmission Loading Relief (TLR) obligations to MISO and PJM markets during a 12-month field test. The Commission directed MISO and PJM to revise their Joint Operating Agreement (JOA) to specify the 3% Market Flow threshold, as well as terms and conditions of the 12-month field test. However, during its April 10, 2008 meeting, the NERC Standards Committee agreed to change the Market Flow threshold from 3% to 5%, effective June 1, 2008 through October 31, 2008 (the remainder of the field test). On May 2, 2008, MISO and PJM, jointly, and MISO and SPP, jointly, filed identical proposed revisions to the CMPs of their respective JOAs. On May 23, 2008, Basin Electric Power Cooperative moved to intervene and protest in these unconsolidated dockets. On June 9, 2008, MISO, PJM, and SPP submitted a Motion for Leave to Answer and Answer to Basin Electric Power Cooperative s May 23, 2008 Protest. On July 1, 2008, the Commission issued an order accepting revisions to the JOAs, effective June 1, 2008, and directing that Applicants submit a compliance filing to include field test methodology in the CMPs by July 16, On July 16, 2008, MISO, PJM and SPP submitted a joint compliance filing containing proposed Appendix H (Market Flow Threshold Field Test Terms and Conditions) of the CMP of their JOAs in compliance with the Commission s July 1, 2008 Order. On August 28, 2008, FERC accepted the changes to Appendix H, effective June 1, Docket No. ER08-995: External Generator Participation in the EIS Market On May 21, 2008, SPP submitted proposed Tariff Revisions to effectuate a short delay of the scheduled implementation of provisions allowing external resources to participate in SPP s EIS Market until a date on or before February 1, SPP will notify the EIS Market participants 30 days in advance of the implementation date and will inform the Commission of the implementation date following the effective date. On July 15, 2008 FERC accepted SPP s Filing to become effective on or before February 1, 2009, upon notice to the Commission. Because SPP s filing did not include revised tariff sheet Nos. 1225, 1226 and 1228 pending in Docket No. ER08-340, these tariff sheets will continue to reflect the old effective date until the pending tariff sheets are accepted by the Commission. On September 23, 2008, SPP submitted to FERC a compliance filing in Docket No. ER containing revised tariff sheets relating to the Energy Imbalance Market. Specifically, the May 21 Filing revised SPP's OATT provisions allowing external of 68

52 resources to participate in SPP's real-time energy imbalance service market. SPP submits revisions to Section 2(j) and 2(m) of Attachment AO to more closely paraphrase the language of the April 21 Order. On October 17, 2008, FERC issued a letter order accepting the May 21 and September 23 compliance filings, effective on or before February 1, 2009, upon notice by SPP, as requested. 18. Docket No. ER : Entergy Mississippi, Inc. Amendments to the Amended and Restated Interconnection and Operating Agreement with Southaven Power, LLC On May 23, 2008, Entergy Mississippi, Inc. submitted amendments to the Amended and Restated Interconnection and Operating Agreement with Southaven Power, LLC. Entergy Mississippi, Inc. filed a Motion for Deferral of Commission Action on June 10, On June 23, 2008, the Commission issued an order requiring additional information in order to evaluate the amended agreement. SPP moved to intervene in this proceeding on June 23, The amendments to the Southaven Agreement are intended to implement the results of the Retrospective Generation Interconnection Analysis (RGIA) conducted by SPP as the ICT. On July 25, 2008, Entergy submitted a response to data request pursuant to the letter from FERC dated June 23, On September 10, 2008, Entergy submitted a Motion for Continued Deferral of Commission Action. Commission action is pending. 19. Docket No. ER : Entergy s Proposed Amendments to the ICT Agreement On June 5, 2008, Entergy submitted proposed amendments to the ICT Agreement executed on November 17, 2006 with SPP. The proposed amendments withdraw Section 6.3 (Regulatory Fines and Penalties) and make certain ministerial corrections to the ICT Agreement incidental to that withdrawal. An effective date of April 15, 2008 is requested, or, in the alternative, June 6, The Louisiana Public Service Commission has intervened. On August 4, 2008, FERC issued an order accepting amendment to the ICT agreement, effective April 15, SPP s request for rehearing is dismissed. 20. Docket No. ER : Entergy Gulf States Louisiana (EGS) submits an amended Interconnection and Operating Agreement (IOA) between RSC Cogen, LLC and EGS of 68

53 On June 6, 2008, Entergy submits an amended Interconnection and Operating Agreement between RSC Cogen, LLC and EGS. On July 9, 2008, SPP filed a Motion to Intervene Out of Time. On September 5, 2008, FERC accepts the Amended IOA, effective August 5, Docket No. ER : Entergy Mississippi, Inc. (EMI) submits an amended IOA between LSP Energy Limited Partnership and EMI On June 6, 2008, Entergy submitted an amended IOA between LSP Energy Limited Partnership and EMI. On July 9, 2008, SPP filed a Motion to Intervene Out of Time. On September 5, 2008, FERC accepted the Amended IOA, effective August 5, Docket No. ER : Attachment AD Revisions (SPP/Southwestern Power Administration Tariff Administration February 2007 Agreement & January 2008 Agreement) On February 1, 2007, SPP and Southwestern Power Administration, by written instrument, extended the term of the Tariff Administration Agreement to January 31, 2008 (February 2007 Agreement). SPP and Southwestern Power Administration agreed to further changes to the Agreement; however, SPP did not file with the Commission the changes pursuant to the February 1, 2007 written instrument. On January 25, 2008, SPP and Southwestern Power Administration agreed to extend the term of the Tariff Administration Agreement again to January 31, 2009, and to other changes to the Agreement, by written instrument signed by both parties (January 2008 Agreement). However, SPP did not immediately submit the revised agreement. Therefore, on June 24, 2008, SPP submitted revisions to Attachment AD of its OATT to modify the Agreement pursuant to both the February 2007 Agreement and the January 2008 Agreement. SPP proposes, among other things, to extend the term of the February 2007 Agreement to January 31, 2008 and the term of the January 2008 Agreement to January 31, Effective dates of February 1, 2007 and February 1, 2008 are requested. On August 20, 2008, FERC accepts the tariff revisions effective February 1, 2007 and February 1, 2008 as requested. 23. Docket No. ER : SPP Filing of Changes to Pricing Zone Rates and Base Plan Rates On July 2, 2008, SPP filed proposed tariff revisions to implement various rate changes stemming from Westar s implementation of a consolidated capital structure in the Westar OATT. SPP is also revising Attachment H of the SPP OATT to incorporate Westar s entire formula rate. An effective date of May 1, 2008 is requested of 68

54 On August 22, 2008, SPP submitted an amendatory filing in order to modify the filing to account for the repayment of the Base Plan Funded Credits to the Redbud Plan. 24. Docket No. ER : SPP-AEP Letter Agreement for a Notification to Construct On July 14, 2008, SPP submitted a letter Agreement between SPP as Transmission Provider, American Electric Power Service Corporation as the Transmission Customer, and AEP as agent for Southwestern Electric Power Company as the Transmission Owner. Comments on this filing were due August 4, AEP submitted a Motion to Intervene and Comments on August 4, On September 9, 2008, FERC issued a letter order accepting the letter agreement between SPP, SWEPCO and AEP concerning the Notification to Construct for the Hempstead to NW Texarkana 345 KV Circuit 1 Project, with an effective date of June 13, 2008, as requested. 25. Docket No. ER : Westar Energy, Inc. Changes to Pricing Zone Rates Effective June 1, 2008 On August 7, 2008, SPP submitted Changes to Pricing Zone Rates for Westar Energy, Inc. On August 22, 2008, SPP submitted to FERC an amendatory filing in Docket No. ER The filing was modified to account for the repayment of the Base Plan Funded Credits to the Redbud Plan. Commission action is forthcoming. 26. Docket No. ER : SPP Bylaws Revisions On August 8, 2008, SPP submitted revised pages to its Bylaws intended to incorporate the modifications that have been accepted by the Commission in Docket Nos. RR and 002, as well as the Bylaws modifications submitted by the North American Electric Reliability Corporation (NERC) in its July 21, 2008 filing in Docket No. RR (July 21 Filing). SPP requests effective dates of May 18, 2007, April 5, 2008, and the date the Commission assigns the Bylaws revisions in the July 21 Filing, respectively, for these revisions. Golden Spread Cooperative, Inc. filed a Motion to Intervene on August 28, On October 6, 2008, FERC issued a letter order. The changes are conditionally accepted in part, and rejected in part, as noted in the order and are effective May 18, 2007 and April 5, 2008, consistent with previous Commission orders. SPP must file, within 30 days of the date of this order, a filing correcting several items. SPP s compliance filing is due November 5, Docket No. ER : Ancillary Services Agreement between KPP and Westar of 68

55 On September 2, 2008 SPP submitted to FERC Modifications to Revised Service Agreement for Ancillary Services and Distribution Facilities and Metering Agreement between Westar Energy and Kansas Power Pool. SPP Service Agreement No. Third Revised An effective date of August 1, 2008 is requested. Commission action is forthcoming. 28. Docket No. ER : Joint Operating Agreement between SPP and Associated Electric Cooperative, Inc. On September 10, 2008, SPP submitted a Joint Operating Agreement between SPP and Associated Electric Cooperative, Inc., effective August 12, Southwest Power Pool, FERC Electric Tariff, Rate Schedule No. 10. The JOA was executed as part of a unanimous settlement agreement reached in Kansas Corporation Commission Docket No. 08-KMOE-028-COC and supersedes a Transmission Coordination Agreement (TCA) between SPP and AECI dated August 19, On September 22, 2008, AECI filed a Motion to Intervene. Commission action is forthcoming. 29. Docket No. ER : ATC Calculation Agreement between Ohio Valley Electric Corporation (OVEC) and SPP On September 12, 2008, OVEC filed an ATC Calculation Agreement between OVEC and SPP, and requested that the Commission determine if it should be filed with FERC. If so, an effective date of September 1, 2008, is requested. On October 1, 2008, SPP filed a Motion to Intervene stating that it is not required to file the agreement under Commission precedent. SPP agrees with OVEC that the agreement is not jurisdictional. Commission action is forthcoming. 30. Docket No. ER : SPP Filing of Pricing Zone and Base Plan Rate Changes for Westar &OG&E On September 15, 2008, SPP Submitted an Amendment to Prizing Zone and Base Plan Rates for Westar Energy, Inc. and Oklahoma Gas & Electric. An effective date of September 30, 2007 is requested. On September 25, 2008 SPP submitted an amendatory filing in order to correct Attachment E due to removing Cleco from that attachment in error. In a filing made September 15, 2008, SPP removed Cleco as a transmission owner and pricing zone under SPP s tariff. The removal was necessary because of Cleco s withdrawal as a transmission-owning member of SPP on November 17, The tariff had not been updated to reflect the withdrawal. The amendatory filing made today was because Cleco was inadvertently removed from Attachment E, which is an index of customers taking point-to-point transmission service under SPP s tariff of 68

56 31. Docket No. ER : Second Amended Interchange Agreement (also known as the OAM Agreement ) between AECI, Empire, GRDA, SWEPCO and Board of Public Utilities of Springfield, Missouri On September 16, 2008, SPP submitted to FERC an executed Second Amended Interchange Agreement between SPP, Associated Electric Cooperative, Inc., The Empire District Electric Company, Grand River Dam Authority, Southwestern Electric Power Company, and the Board of Public Utilities of Springfield, Missouri designated as Service Agreement No An effective date of August 11, 2008 is requested. This agreement supersedes the Amended Interchange Agreement that was accepted by the Commission on February, 25, The Amended Interchange Agreement was submitted by SWEPCO in Docket No. OA on December 31, On September 23, AECI submitted a Motion to Intervene. Commission action is forthcoming. 32. Docket No. ER : SPP Filing of Pricing Zone Rate Changes for Public Service Company of Oklahoma (PSO) and SWEPCO On September 17, 2008, SPP submitted changes to Pricing Zone Rates intended to implement a rate change for PSO and SWEPCO. An effective date of February 1, 2008 is requested. Commission action is forthcoming. M. SPP Tariff Filings 1. Docket No. OA08-5: SPP Order 890 Compliance Filing - Unreserved Use Penalty, Penalty Revenues & Attachment C Revisions regarding the Methodology to Assess Available Transfer Capability (ATC) On May 16, 2008, the Commission issued an order accepting SPP s October 11, 2007 compliance filing, as modified. SPP was directed to revise the unreserved penalty charge to bring it into line with FERC precedent and submit a one-time compliance filing within 30 days wherein SPP must propose a methodology for distributing revenues. SPP must also modify Attachment C and R of the Tariff. On June 16, 2008, SPP filed a request for rehearing on the May 16 Order requesting that the Commission grant rehearing of its determination that SPP must revise Attachment C to provide a clear definition for total transfer capability (TTC), a detailed explanation of its TTC calculation methodology, as well as a list of the databases used to calculate TTC. On June 16, 2008, SPP submitted a compliance filing pursuant to the May 16 Order. SPP revised the unreserved use penalty in Section 13.7 and SPP also removed language from various sections in its Tariff providing that penalty revenues will be used to reduce SPP s administrative costs, incorporated language referencing NERC s TLR of 68

57 Procedures into Attachment R, and re-incorporated the Commission s previous rollover policy into Section 2.2 of its Tariff. An effective date of October 11, 2007 is requested. On July 16, 2008, FERC granted SPP s request for rehearing of the May 16 Order. On August 11, 2008, SPP submitted a compliance filing pursuant to the May 16 Order. SPP is incorporating its rollover policies that were adopted by Order 890. An effective date of August 11, 2008 is requested. 2. Docket No. OA08-60: SPP Request for Waiver of Rollover Policy in Order No. 890 for Certain Potential SPP Firm Transmission Service Customers On December 14, 2007, SPP requested that the Commission waive the applicability of its revised policies concerning rollover rights adopted in Order No. 890 for certain potential SPP firm transmission customers. On September 30, 2008, FERC issued an Order Granting Limited Order No. 890 Waiver Request, as requested by SPP on December 14, On October 6, 2008, FERC issued an Errata to its September 30, 2008 Order correcting the third sentence of Paragraph 9 to state "...transmission service requests submitted after July 13, 2007, but on or before September 30, 2007, will be subject to the pre- Order No. 890 rollover provisions). 3. Docket No. OA08-61: SPP Order No. 890 Compliance Filing Attachment O Revisions for Coordinated and Regional Planning Process On December 14, 2007, SPP submitted revisions to the SPP Tariff in compliance with the Commission s directives to file a proposal for a coordinated and regional planning process that complies with the planning principles adopted in Order No Xcel filed a motion to intervene and conditional protest on January 7, 2008, protesting one aspect of proposed Attachment O relating to Information Exchange. On January 22, 2008, SPP filed an answer to the comments and requests for modification filed in this proceeding by Xcel and ITC Great Plains, respectively. On July 11, 2008, the Commission accepted SPP s December 14, 2007 compliance filing, as modified, effective December 14, 2007, and directed SPP to submit an additional compliance filing by October 9, FERC also announced that, beginning in 2009, the Commission will convene regional technical conferences similar to those conferences held in 2007 leading up to the filing of the Attachment K compliance filings for the purpose of determining the progress and benefits realized by each transmission provider s transmission planning process, obtaining customer and other stakeholder input, and discussing any areas that may need improvement. On August 5, 2008, FERC issued an Errata Notice correcting footnote 18 in the July 11 Order of 68

58 On August 7, 2008, SPP submitted a Motion for Extension of Time, requesting 120 days to submit compliance filing pursuant to the July 11 Order. On September 12, 2008, FERC granted SPP an extension of time to and including February 6, 2009, to comply with FERC s July 11 Order. 4. Docket No. OA08-75: Entergy Compliance Filing Incorporating Order No. 890-A s Nonrate Terms and Conditions into Entergy s OATT On March 17, 2008, Entergy submitted a compliance filing incorporating Order No A s non-rate terms and conditions into Entergy s Third Revised Volume No. 3 OATT. An effective date of July 13, 2007 is requested. Revised versions of Attachments C, D, and E will be submitted in a separate filing upon the conclusion of the stakeholder process. SPP moved to intervene in this docket on April 7, Docket No. OA08-76: E.ON U.S. Order 890-A Compliance Filing Description of Transmission Provider Responsibilities, Attachments C & K Revisions, & Proposal of a New Schedule 13 (Unreserved Use Penalty) On March 17, 2008, E.ON U.S., on behalf of LG&E and KU, submitted revisions to the LG&E/KU OATT in compliance with requirements of Order No. 890-A. E.ON has further revised the LG&E/KU OATT to delineate responsibilities of the Transmission Provider under Order Nos. 890 and 890-A which have been delegated to LG&E/KU, the ITO, and the Tennessee Valley Authority (TVA) as the Reliability Coordinator. E.ON has also made certain discretionary changes to Attachments C and K to the LG&E/KU OATT in accordance with the directives of Order No. 890-A. E.ON has also proposed a new Schedule 13 to the OATT to implement unreserved use penalties as required by Order Nos. 890 and 890-A. An effective date of March 17, 2008 is requested. On April 8, 2008, SPP, acting as the ITO, filed a Motion for Leave to Intervene Out of Time. Commission action is pending. 6. Docket No. OA08-104: SPP Order 890-A Compliance Filing Revising the SPP Tariff with Limited Departures from the Order No. 890-A Pro Forma On April 15, 2008, SPP submitted Tariff Revisions incorporating specific changes to the Order No. 890 pro forma OATT adopted by the Commission in Order 890-A. SPP has not incorporated certain pro forma OATT reforms related to conditional firm service, planning redispatch service, energy imbalance and generator imbalance, and unreserved use penalties. An effective date of April 15, 2008 is requested. Several parties have moved to intervene in this proceeding of 68

59 On May 21, 2008, SPP filed an Answer to Protests and Requests for Modification, in which SPP contends that SPP is not required to adopt Conditional Firm Service because SPP has a Real-Time EIS Market. Commission action is forthcoming. 7. Docket No. ER : SPP Administrative Fee Cap Filing On July 31, 2008, Southwest Power Pool, Inc filed revised tariff sheets amending Schedule 1-A of the Open Access Transmission Tariff in order to increase the rate cap for its Tariff Administration Service Charge under ER Golden Spread Cooperative, Inc. filed a Motion to Intervene and Conditional Protest on August 19, The Commission issued a Letter Order on September 18, 2008, accepting SPP's request to increase SPP s rate cap of Schedule 1-A Tariff Administration Service Charge from $0.20/MWh to $0.225/MWh. The increase is effective on October 1, Docket No. ER : Combined Aggregate Study Filing On August 8, 2008, SPP filed Revised Tariff Sheets to Modify the Transmission Request Aggregate Study Process (Combined Aggregate Study Filing). Revisions were made in order to adopt measures to improve the processing of transmission service requests and the Aggregate Transmission Service Study (ATSS) procedure. Specifically, SPP proposed to revise Attachment Z1 and other relevant Tariff provisions to combine the transmission service requests received during pairs of consecutive open seasons into a single ATSS in order to reduce the number of studies SPP must perform in processing its transmission service request queue. Numerous parties filed Motions to Intervene. AEP and Empire filed Comments. No party filed to protest. On September 15, 2008, SPP filed an answer responding to Comments. Specifically, SPP states that this action is not meant to be a permanent change in the aggregate study process, nor is it the only reform that SPP is considering at this time. SPP plans to submit a more comprehensive proposal in the early part of On October 7, 2008, FERC issued a letter order accepting the tariff revisions, effective August 9, 2008 as requested. 9. Docket No. ER : Balanced Portfolio for Economic Upgrades Filing On August 15, 2008, Southwest Power Pool, Inc submitted amendments to its Open Access Transmission Tariff to establish (i) a process for including a balanced portfolio of economic upgrades into the SPP Transmission Expansion Plan and (ii) a regional postage stamp rate design for recovery of costs of such upgrades. In addition, SPP proposes to amend the provisions relating to the treatment of upgrades that result in the deferral or displacement of other upgrades. SPP requests an effective date of October 17, 2008 for these Tariff modifications of 68

60 Several parties filed Motions to Intervene. Four parties filed Comments, all of which expressed support for the balanced portfolio initiative. No parties filed to protest. On September 22, 2008, Southwest Power Pool, Inc. submitted to FERC an Answer To Intervenors' Comments in Docket No. ER Specifically, SPP states it initially proposes to use an adjusted production cost metric to determine the benefits of a potential balanced portfolio. SPP has also committed to continue to evaluate and explore with the stakeholders via the transmission planning process any additional metrics and criteria which have quantifiable economic effects and to amend the Tariff to include those metrics as appropriate SPP states that ITC Great Plains suggestion that at least some of these additional benefit measures should be incorporated into this proposal by a date certain so that these additional metrics will be used for the balanced portfolios after the first balanced portfolio planned by SPP for January 2009 might hinder the opportunity for stakeholder input into the determination of the additional benefit metrics that should be included in the balanced portfolio benefit analysis. SPP also states that evaluating costs and benefits of a potential Balanced Portfolio over a ten-year period is just and reasonable. In addition, SPP states the proposal is consistent with the transparency principle of Order No. 890 and does not involve arbitrary decisionmaking by SPP, issues regarding trapped generation are properly addressed in the Stakeholder Process, and the development of Seams Agreements between SPP and its neighbors and Third-Party impacts are beyond the scope of this proceeding. SPP also addressed ITC Great Plains request for confirmation as to whether two of its projects (Kansas V-Plan and The KETA Project) are eligible for inclusion in a balanced portfolio. On September 29, 2008, SPP submitted an Errata Answer to Intervenors' Comments under the SPP "Balanced Portfolio" filing in order to correct the sentence beginning on page 13 and continuing to page 14 of the answer filed on September 22, On October 16, 2008, FERC issued an Order Accepting Tariff Revisions, as Modified. SPP is directed to make a compliance filing by December 15, 2008, with provisions ensuring that system design software results needed for stakeholders to verify the application of the assumptions in creating the adjusted production cost-benefit metrics will be made available, and clarifying that costs incurred by transmission owners or zones due to third-party impacts are included among the factors affecting the revenue requirement associated with the economic upgrade, as discussed in the body of this order. 10. Docket No. ER : Secondary Network Service Tariff Revisions On September 23, 2008, Southwest Power Pool, Inc. submitted to FERC Revisions to SPP's Open Access Transmission Tariff. Specifically, SPP proposes to limit the transmission capacity Network Customers may reserve for secondary service in any single hour. Commission action is forthcoming. 11. Docket No. ER : SPP Revisions to Bylaws, Tariff and Membership Agreement Nebraska Membership Changes of 68

61 On September 30, 2008, SPP submitted proposed amendments to its Bylaws, Open Access Transmission Tariff ( OATT ), and Membership Agreement, in order to facilitate Nebraska Public Power District ( NPPD ), Omaha Public Power District ( OPPD ), and Lincoln Electric System ( LES ) becoming Members of SPP. Commission action is forthcoming. N. ICT s Third Quarterly Performance Report for 2008 (Docket No. ER ) Entergy s ICT Proposal is addressed in FERC Docket Nos. ER and ER , 4 as well as Louisiana Public Service Commission (LPSC) Docket No. U and Arkansas Public Service Commission (APSC) Docket No U. The ICT s Third Quarterly Performance Report for 2008 was filed on September 30, 2008 in accordance with FERC s orders approving the establishment of the ICT and section 7 of Attachment S to Entergy s OATT. Entergy continues to notify the Commission of data-reporting and AFC-related issues pursuant to the Commission s April 24, 2006 Order. O. Arkansas Regulatory Proceedings 1. Docket No U: SWEPCO Turk Coal Plant CECPN Approval Arkansas Electric Cooperative Corporation (AECC), OMPA and the East Texas Electric Cooperative (ETEC) executed a Construction, Ownership and Operating Agreement pertaining to the John W. Turk, Jr. plant, effective December 13, 2007, as noticed by SWEPCO on February 4, On January 24, 2008, the Intervenors filed a motion to consolidate in this proceeding requesting that the APSC: (1) find that both Order No. 3 in Docket No U and Condition No. 2 of Order No. 11 in Docket No U have been violated; (2) reopen Docket Nos U and U and consolidate them with Docket Nos U and U, and (3) stay consideration of all matters until SPP has completed the congestion study required by the Commission, and until applications for all of the electric and gas transmission lines that will serve the Turk plant are filed and consolidated. APSC staff, the Arkansas Attorney General s Office and SWEPCO each submitted filings in opposition of Intervenors Motion to Consolidate. On February 8, 2008, Intervenors requested an extension of time to file a responsive pleading to SWEPCO s Response to Intervenors Motion to Consolidate until 10 days after their Petition to Intervene in Docket Nos U and U is acted upon by the Commission. The APSC has not yet acted on this request. Monthly status reports are being filed by SWEPCO, as required by Order No. 11. SWEPCO reports that development activities associated with preparation of the Turk site for construction began in January 2008 and are ongoing. The Arkansas Department of 4 FERC Docket No. ER replaced Entergy s Initial ICT Proposal in Docket No. ER04-699, which closed June 30, of 68

62 Environmental Quality is also expected to issue a final Air Permit for the facility by the 3 rd quarter of For associated activity in Louisiana and Texas, please see LPSC Docket No. U and PUCT Docket No For the associated appeal of the APSC s Order No. 11 by Intervenors, please refer to Arkansas Court of Appeals Case No. CA , presented in the detailed docket status report on the SPP website. 2. Docket Nos U, U & U: SWEPCO CECPN Proceedings 138 kv Southeast Texarkana, 138 kv Sugar Hill & Northwest Texarkana 345 kv Transmission Lines On August 4, 2008, the APSC established a procedural schedule in these dockets: Staff/Intervenor Rebuttal Testimony was due September 19, 2008; Company/SPP Surrebuttal Testimony was due October 17, 2008; and Consecutive hearings are set to begin on October 28, 2008 for Docket Nos U, U and U. SPP filed Jay Caspary s Rebuttal Testimony on October 14, a. Docket No U (138 KV Southeast Texarkana Transmission Line) On January 15, 2008, SWEPCO filed an application for a CECPN seeking authority to build a transmission substation at the John W. Turk, Jr. Generation Facility and a 138 kv transmission line originating at SWEPCO s existing Southeast Texarkana Station in Texarkana, Arkansas and terminating at the proposed Turk Station. This proposed 138 kv transmission line is one of two new 138 kv transmission lines that will connect the Turk Generation Facility to the existing transmission infrastructure. b. Docket No U (138 kv Sugar Hill Transmission Line) On January 15, 2008, SWEPCO filed an application for a CECPN seeking authority to construct a new transmission substation at the John W. Turk, Jr. Generation Facility and a new 138 kv transmission line originating at SWEPCO s existing Sugar Hill Station, located near Texarkana, Arkansas, and terminating at the proposed Turk Station. c. Docket No U (Northwest Texarkana 345 kv Transmission Line) On July 1, 2008, SWEPCO filed a third CECPN Application in Docket No U to construct a new 345 kv transmission line originating at the existing Northwest Texarkana Station near the city of Leary, Bowie County, Texas, traversing approximately 30 miles through Bowie County, Texas, and Hempstead, Miller and Little River Counties, Arkansas, and terminating at the proposed Turk Station located on the premises of the John W. Turk, Jr. Generation Facility in Hempstead County, Arkansas. 3. Docket No U (Amendments to Rules of Practice and Procedure) On September 25, 2008, the APSC opened this docket for the purpose of amending its Rules of Practice and Procedure of 68

63 The APSC will appoint as members of a Drafting Committee (DC) certain attorneys who have regularly appeared before the Commission for may years and therefore have extensive experience with practice before the Commission under the Rules. Any attorney with such practice and experience may request appointment by filing within seven (7) days of the date of this Order a letter requesting appointment. Thereafter, the Commission will designate the specific members of the DC. The DC shall include as appropriate and needed the Secretary of the Commission and the Information Technology Director of the Commission. The Chairman of the DC shall be Ms. Valerie Boyce, General Counsel for the General Staff of the Commission. Once the members are appointed, the DC shall develop and file within seventy-five (75) days the initial draft of a proposed comprehensive rewrite of the Rules. Thereafter, the APSC will establish a procedural schedule for the filing of initial and reply comments and a public hearing on the proposed amended Rules. The Secretary of the Commission shall serve a copy of this Order on all jurisdictional public utilities, the Attorney General of the State of Arkansas, the General Staff of the Commission and upon legal counsel for the Arkansas Electric Energy Consumers, Inc. and the Arkansas Gas Consumers, Inc. Such entities may become official parties to this Docket by filing within twenty (20) days of this Order a letter stating the intent to participate as an official party. A formal petition to intervene will not be required of such entities. Other entities desiring official party status shall file a formal petition to intervene pursuant to Rule 3.04 of the Rules. 4. Docket No U (All Things SPP RTO and ICT) On September 25, 2008, the APSC opened this docket to inquire into electric transmission issues within the areas served by the Southwest Power Pool Regional Transmission Organization and the Entergy Corporation as those issues might impact the electric service within Arkansas. The SPP-RTO, all jurisdictional electric public utilities, the General Staff of the Commission, the Attorney General and the Arkansas Electric Energy Consumers were granted official party status. The SPP-RTO is to file a briefing document not less than 30 days after the filing with FERC of the next quarterly report of the SPP-RTO as the ICT (Independent Coordinator of Transmission) and should also include a briefing of the monthly activities of the SPP- RTO market monitor during After that filing, the Commission will establish an expanded procedural schedule allowing for reply comments and public hearings as needed. On October 17, 2008, APSC issued an Order of Clarification. It requires SPP Inc. to file the most recent ICT Quarterly Report and the most recent monthly Market Monitoring Report by October 30, It also requires us, from today forward, to file these reports contemporaneously with APSC as they are filed with FERC (no limit on how long we have to do this). On January 15, 2009, the remainder of SPP s briefing document is due of 68

64 5. Docket No U (Innovative Approaches to Ratebase, Rate of Return Ratemaking) On September 25, 2008, the APSC opened this docket for the consideration of innovative approaches to utility regulation in Arkansas to address the many challenges facing the electric and natural gas public utility industries. The Attorney General, Arkansas Electric Energy Consumers, Arkansas Gas Consumers and the General Staff of the Arkansas Public Service Commission and all jurisdictional gas and electric companies were granted party status and allowed 45 days to file comments. Comments are due November 7, Docket No U (Sustainable Energy Docket) On October 7, 2008, the APSC opened this docket to explore the expanded development of Sustainable Energy Resources (SER) within the State of Arkansas with the end result being the development of a Sustainable Energy Resources Guide for this Commission to use in promoting SER initiatives. Parties to dockets R, R, U and U, General Staff of the Arkansas Public Service Commission and the Attorney General are invited to participate in the Collaborative and to submit comments, respond to the questions posed in this and subsequent orders and to make suggestions for the efficient and productive conduct of this inquiry by December 15, The first collaborative sessions will be the jointly-sponsored appearance of Duke Energy Chief Executive Officer Jim Rogers at the William Jefferson Clinton School of Public Service on October 14, This will be followed by the Commission's hosting a panel of invited utility CEOs to present company position on SER issues and respond to written and oral questions from parties and the Commission at a date to be determined. The Commission will sponsor other public forums and guest speakers to address topics of interest to the Commission and the Collaborative. P. Kansas Regulatory Proceedings 1. Docket No. 08-KMOE-028-COC: KAMO/AECI CCN Application (Blackberry Chouteau GRDA1 345 kv Transmission Line) On July 11, 2007, KAMO filed a CCN application with KCC for a limited certificate of public convenience and authority to construct, own, and operate transmission facilities located in the State of Kansas. AECI filed an amendment to the Application on November 26, 2007 to join the action. KAMO/AECI request a Transmission Rights Only certificate that will allow it to construct a 345 kv transmission line between Missouri and Oklahoma which may pass through the southeast corner of Kansas. The connections will be from a 345 kv line owned by AECI near Jasper, Missouri to the GRDA Unit kv station located near Chouteau, Oklahoma. SPP moved to intervene in this proceeding on July 26, 2007 and was granted intervenor status on August 21, of 68

65 The KCC issued an order on April 11, 2008 continuing the hearing from April 15-16, 2008 and ordering SPP to commence a cost/benefit analysis study concerning the transmission line proposed in this proceeding. SPP presented the results of its supplemental analysis at a technical conference in Little Rock, Arkansas on June 2, On June 3, 2008, SPP published its final report entitled, Supplemental SPP Analysis of Blackberry Chouteau GRDA1 345 kv Project Per KCC Order Issued April 11, This study was endorsed by the TWG on June 11, 2008 as providing the opportunity for potentially impacted parties/stakeholders to participate. On June 20, 2008, SPP published an additional report entitled, Alternative Solutions for AECI and KAMO: Supplemental SPP Analysis of Blackberry Chouteau GRDA1 345 kv Project Per KCC Order Issued April 11, On June 23, 2008, SPP filed the Supplemental Testimony of Keith Tynes and the Direct Testimony of Pat Bourne. Supplemental testimony has also been filed by Larry Holloway of KCC staff, Tom Stuchlik of Westar, Chris Bolick of AECI, and Chris Cariker and Ted Hilmes of KAMO. On July 9, 2008, the parties met at the Commission s offices in Topeka, Kansas for a settlement conference. As a result of those efforts and subsequent discussions, a settlement was reached on July 14, On July 14, 2008, AECI, KAMO, SPP, Westar, and Empire filed a Joint Motion for Continuance of the evidentiary hearing from July 15-16, 2008 until July 31, 2008 at 1:30 pm. KAMO/AECI, SPP and KCC Staff Testimony in Support of Settlement were due July 28, A settlement hearing was held at the KCC in Topeka, Kansas on July 31, On August 12, 2008, the KCC issued an Order Approving Unanimous Settlement granting AECI/KAMO a limited certificate of public convenience to construct, own, and operate the proposed transmission line pursuant to the terms of the Agreement. AECI shall provide the KCC and the parties and update one year after the date the Order becomes final as to the progress of further agreement between AECI and SPP on congestion management and other issues. On September 10, 2008, the Joint Operating Agreement executed pursuant to the August 12, 2008 Order was filed with FERC in Docket ER Docket Nos. 08-ITCE-936-COC, 08-ITCE-937-COC, 08-ITCE-938-COC: ITC Great Plains Amendments to its Certificate of Public Convenience and Authority to Construct, Own, Operate and Manage Wholesale Electrical Transmission Facilities in Portions of Certain Counties in the State of Kansas of 68

66 SPP moved to intervene in these proceedings on April 25, The KCC granted intervention on September 2, On October 2, 2008, KCC Staff issued its report and recommendation, in which it recommends that these three dockets and the Prairie Wind Docket (08-PWTE COC) move forward in three phases: a. Phase 1a Resolving the issues of Prairie Wind s Application for a Limited Certificate b. Phase 1b Resolving the issues of consolidating the ITC dockets c. Phase 2 Resolving the issue of who should receive a certificate for the proposed Wichita to Spearville Electric Circuit a. Docket No. 08-ITCE-936-COC (Ford, Kiowa, Clark & Comanche Counties) On April 11, 2008, ITC Great Plains filed an application for an amendment to its Certificate of Public Convenience and Authority to construct, own, operate and manage wholesale electrical transmission facilities in portions of the Counties of Ford, Kiowa, Clark and Comanche in the State of Kansas. This docket pertains to the initial segment of the V-Plan (northern half or Kansas portion of the X-Plan ). ITC Great Plains filed two other applications to amend its certificate of public convenience for the middle and final segments of the V-Plan in Docket Nos. 08-ITCE and 08-ITCE , respectively. SPP moved to intervene in this proceeding on April 25, On May 8, 2008, ITC Great Plains filed its response to Westar s April 25, 2008 motion to intervene, consolidate ITC s three applications into a single proceeding, or dismiss the applications for failing to provide a basis for the requested amendment to ITC Great Plains certificate. Westar filed a Reply on May 19, On May 27, 2008, Kansas Power Pool filed Resolution No in Docket Nos. 08- ITCE-936-COC, 08-ITCE-937-COC and 08-ITCE-938-COC. The resolution, passed by the Kansas Power Pool Board of Directors on May 14, 2008, is in support of transmission line construction and expansion in Kansas. On June 2, 2008, ITC Great Plains filed a response to Westar s May 19, 2008 Reply. Westar filed a response to ITC Great Plains Response on June 16, Sunflower Electric Cooperative, Mid-Kansas Electric Co., LLC and KCPL have moved to intervene. On September 2, 2008, an Order Granting Petitions to Intervene was issued in Dockets 08-ITCE-936-COC, 08-ITCE-937-COC, 08-ITCE-938-COC, and 08-PWTE-1022-COC. In this order, the KCC also directed Staff to file a Report and Recommendation that (1) summarizes issues the Commission will need to decide including factual questions that will need to be determined; (2) proposes procedures to address these issues; and (3) of 68

67 suggests a schedule for resolving these dockets. Comments from parties regarding the Report and Recommendation are due 15 days after the report is filed. On October 2, 2008, Staff issued the Report and Recommendation. Comments on this report are due October 20, SPP filed comments on October 20, b. Docket No. 08-ITCE-937-COC (Comanche, Clark & Barber Counties) On April 11, 2008, ITC Great Plains filed for an amendment to its Certificate of Public Convenience and Authority to construct, own, operate and manage wholesale electrical transmission facilities in portions of the Counties of Comanche, Clark and Barber, in the State of Kansas. This docket pertains to the middle segment of the V-Plan (northern half or Kansas portion of the X-Plan ). SPP moved to intervene in this proceeding on April 25, On May 8, 2008, ITC Great Plains filed its response to Westar s April 25, 2008 motion to intervene, consolidate ITC s three applications into a single proceeding, or dismiss the applications for failing to provide a basis for the requested amendment to ITC Great Plains certificate. Westar filed a Reply on May 19, On May 27, 2008, Kansas Power Pool filed Resolution No in Docket Nos. 08- ITCE-936-COC, 08-ITCE-937-COC and 08-ITCE-938-COC. The resolution, passed by the Kansas Power Pool Board of Directors on May 14, 2008, is in support of transmission line construction and expansion in Kansas. On June 2, 2008, ITC Great Plains filed a response to Westar s May 19, 2008 Reply. Westar filed a response to ITC Great Plains Response on June 16, Sunflower Electric Cooperative, Mid-Kansas Electric Co., LLC and KCPL have moved to intervene. On September 2, 2008, an Order Granting Petitions to Intervene was issued in Dockets 08-ITCE-936-COC, 08-ITCE-937-COC, 08-ITCE-938-COC, and 08-PWTE-1022-COC. In this order, the KCC also directed Staff to file a Report and Recommendation that (1) summarizes issues the Commission will need to decide including factual questions that will need to be determined; (2) proposes procedures to address these issues; and (3) suggests a schedule for resolving these dockets. Comments from parties regarding the Report and Recommendation are due 15 days after the report is filed. On October 2, 2008, Staff issued the Report and Recommendation. Comments on this report are due October 20, SPP filed comments on October 20, of 68

68 c. Docket No. 08-ITCE-938-COC (Barber, Harper, Kingman, Sumner & Sedgwick Counties) On April 11, 2008, ITC Great Plains filed for an amendment to its Certificate of Public Convenience and Authority to construct, own, operate and manage wholesale electrical transmission facilities in portions of the Counties of Barber, Harper, Kingman, Sumner and Sedgwick, in the State of Kansas. This docket pertains to the middle segment of the V-Plan (northern half or Kansas portion of the X-Plan ). SPP moved to intervene in this proceeding on April 25, On May 8, 2008, ITC Great Plains filed its response to Westar s April 25, 2008 motion to intervene, consolidate ITC s three applications into a single proceeding, or dismiss the applications for failing to provide a basis for the requested amendment to ITC Great Plains certificate. Westar filed a Reply on May 19, On May 27, 2008, Kansas Power Pool filed Resolution No in Docket Nos.08- ITCE-936-COC, 08-ITCE-937-COC and 08-ITCE-938-COC. The resolution, passed by the Kansas Power Pool Board of Directors on May 14, 2008, is in support of transmission line construction and expansion in Kansas. On June 2, 2008, ITC Great Plains filed a response to Westar s May 19, 2008 Reply. Westar filed a response to ITC Great Plains Response on June 16, Sunflower Electric Cooperative, Mid-Kansas Electric Co., LLC and KCPL have moved to intervene. On September 2, 2008, an Order Granting Petitions to Intervene was issued in Dockets 08-ITCE-936-COC, 08-ITCE-937-COC, 08-ITCE-938-COC, and 08-PWTE-1022-COC. In this order, the KCC also directed Staff to file a Report and Recommendation that (1) summarizes issues the Commission will need to decide including factual questions that will need to be determined; (2) proposes procedures to address these issues; and (3) suggests a schedule for resolving these dockets. Comments from parties regarding the Report and Recommendation are due 15 days after the report is filed. On October 2, 2008, Staff issued the Report and Recommendation. Comments on this report are due October 20, SPP filed comments on October 20, Docket No. 08-PWTE-1022-COC: Prairie Wind Application for a Certificate of Public Convenience and Authority of 68

69 On May 19, 2008, Prairie Wind Transmission, LLC filed an application for a Certificate of Public Convenience and Authority to site, construct, own, operate and maintain bulk electric transmission facilities in the State of Kansas. As an initial project, Prairie Wind proposes to construct a new 765 kv transmission system comprised of two segments. Prairie Wind anticipates that one segment will run west-southwest from a new 765 kv or existing substation near Wichita, Kansas to a new 765 kv substation near Medicine Lodge, Kansas and then west-northwest to a new or existing station near Spearville, Kansas and that the other segment will run from the new Medicine Lodge 765 kv substation south-southwest to the Kansas-Oklahoma border. The Direct Testimony of Kelly Harrison (Westar), Lisa Barton (AEP), Mark Ruelle (Westar) and Wayne Irmiter (MidAmerican Energy Holdings Company) has been filed on behalf of Prairie Wind. SPP moved to intervene in this proceeding on June 6, ITC Great Plains and KCPL have also moved to Intervene. On September 2, 2008, an Order Granting Petitions to Intervene was issued in Dockets 08-ITCE-936-COC, 08-ITCE-937-COC, 08-ITCE-938-COC, and 08-PWTE-1022-COC. In this order, the KCC also directed Staff to file a Report and Recommendation that (1) summarizes issues the Commission will need to decide including factual questions that will need to be determined; (2) proposes procedures to address these issues; and (3) suggests a schedule for resolving these dockets. Comments from parties regarding the Report and Recommendation are due 15 days after the report is filed. On October 2, 2008, Staff issued the Report and Recommendation. Comments on this report are due October 20, In the October 2, 2008 report, KCC Staff recommends that this docket and the three ITC Great Plains dockets (08-ITCE-936-COC, 08-ITCE-937-COC, 08-ITCE-938-COC) move forward in three phases: a. Phase 1a Resolving the issues of Prairie Wind s Application for a Limited Certificate b. Phase 1b Resolving the issues of consolidating the ITC dockets c. Phase 2 Resolving the issue of who should receive a certificate for the proposed Wichita to Spearville Electric Circuit SPP filed comments on October 20, Docket No. 08-WSEE-609-MIS: Approval of the Joint Application of Westar and Kansas Gas & Electric Company for a Siting Permit 345 kv Transmission Line in Butler, Sumner & Cowley Counties, Kansas (Rose Hill to Sooner Case) On December 27, 2007, Westar submitted an Application for a siting permit to construct a 345 kv transmission line from the Rose Hill Substation near Rose Hill, Kansas to the Kansas/Oklahoma border. SPP moved to intervene on January 28, 2008 and was granted intervenor status on March 4, of 68

70 An evidentiary hearing was held March 18-19, On April 25, 2008, the KCC issued a written order granting Westar's Application conditional upon inclusion of the Burley/Bannon Alternative. A Motion for Reconsideration of Bois D-Arc, Inc. was denied by the KCC on June 16, 2008 because Petitioner was not a party to this proceeding and lacks standing to seek reconsideration. Q. Louisiana Regulatory Proceedings 1. Docket No. R-26172, Subdocket C: Possible Suspension of, or Amendments to, the Louisiana Public Service Commission s Market Based Mechanism Order to Make the Process More Efficient and to Consider Allowing the Use of On-line Auctions for Competitive Procurement On January 2, 2008, the Notice of Second Proposed Rule was received on behalf of staff. An open session was held January 16, 2008 and the LPSC voted to accept the Staff Recommendation and amend the Market Based Mechanism Order to include language permitting internet-based auctions. On June 16, and , post technical conference comments were filed on behalf of AEP/SWEPCO, Gulf States Louisiana, LLC and Entergy Louisiana, LLC, Joint Stakeholders, Louisiana Energy Users Group, SUEZ Energy North America, Calpine Corporation, and Entegra Power Group, LLC, and Cleco Power, LLC. Docket Nos. R-26172, Subdocket C and R have been consolidated. Docket No. R involves possible modifications to the September 20, 1983 General Order to allow for more expeditious certifications of limited-term resource procurements and an exception for annual and seasonal liquidated damages block energy purchases. 2. Docket Nos. U-27866, Subdocket B & U-29702: SWEPCO s Application for Certification of Contracts for the Purchase of Capacity and to Purchase, Operate, Own and Install Peaking, Intermediate and Baseload Generating Facilities On March 19, 2008, at its regularly scheduled Business and Executive Session, the LPSC unanimously approved SWEPCO s application in this docket to construct, own, and operate the Turk Plant, pursuant to the Louisiana Public Service Commission s Market Based Mechanism Order (MBM) and LPSC s 1983 General Order. A hearing was held April 8-10, A written order was issued on April 29, The Commission adopted a variety of ratepayer protection and reporting conditions and SWEPCO must comply with those conditions. Post-hearing briefs have been filed. 3. Docket No. R-30738: Louisiana Public Service Commission, ex parte. In re: Identification of Regulatory Obstacles to Merchant Transmission Investment in Louisiana of 68

71 and Recommendation of Potential Regulatory Framework Governing Merchant Transmission Investment in Louisiana This docket was opened pursuant to Commissioner Field s directive at the Commission s August 12, 2008 meeting. LPSC Staff is currently seeking comments on (i) any regulatory obstacles and (ii) the following possible regulatory frameworks governing the interaction of jurisdictional electric utilities and merchant transmission companies: (1) Should the stakeholder process (sponsored by the ICT in the case of Entergy and SPP for Cleco and SWEPCO) continue to be used to identify transmission projects that promise reliability and/or economic benefits? (2) Should the ICT or SPP, as the neutral third party and after weighing the arguments, advise on whether a proposed transmission project is in the public interest? (3) Should the utility, in whose territory the recommended project is to be located, be required to provide the Commission with the following information: (a) whether they will build the recommended transmission project (subject to contributions under the applicable cost allocation formula), the cost of building the proposed project, and when the project will be placed in service, or (b) why they will not build the recommended project? (4) If the utility will not build the recommended transmission project, of if a merchant transmission company can build it cheaper or quicker, should the merchant transmission company be able to petition the Commission for the right to construct the recommended project? The decision of a merchant transmission company to build or not build a particular transmission project would have no bearing on the utility s prudence obligations. (5) Any additional items/issues relative to the above. Interventions and comments were due September 16, 2008 (25 days from the publication of LPSC Bulletin No. 913, August 22, On September 15, 2008, SPP filed Petitions to Intervene in this matter on behalf of the SPP-RTO and the SPP-ICT. R. Mississippi Regulatory Proceeding Docket No AD-158: Proceeding to Review Statewide Energy Generation Needs On April 30, 2008, the Mississippi Public Service Commission (MPSC) opened this docket to develop an on-going review of the five-year long-range energy needs for the State of Mississippi. The MPSC directed all electric utilities and subject to the Commission s jurisdiction to submit documentation and proofs as to forecasts, plans and future electric generation needs by July 31, SPP moved to intervene in this proceeding on June 9, 2008 and was granted intervenor status on June 10, of 68

72 Initial public hearings commenced August 18, 2008 for oral testimony and comments. Bruce Rew, on behalf of the SPP ICT, participated in the public hearing by providing a presentation on the ICT as requested by the Commission staff. S. Missouri Regulatory and Circuit Court Proceedings 1. Docket No. EO : Aquila s Application to Transfer Operational Control of Certain Transmission Assets to MISO On August 20, 2007, Aquila filed an application with the Missouri Public Service Commission (MoPSC) to transfer operational control of certain transmission assets to MISO. SPP moved to intervene on September 10, 2007 and was granted intervenor status on September 28, An evidentiary hearing was held April 14-15, 2008 in Jefferson City, Missouri. At the conclusion of the hearing, the parties were directed to file post-hearing briefs addressing the meaning of the not detrimental to the public interest standard. SPP filed its post-hearing brief on May 29, 2008, requesting that the Commission reject Aquila s Application. On October 9, 2008, the Commission issued an order stating that Aquila s proposal to transfer operational control of its transmission assets to Midwest ISO would cause a detriment to the public interest and on that basis, Aquila s application is denied. The order goes on to state: As established by the independent and credible cost benefit analysis performed by CRA International, the net benefit to Aquila of joining Midwest ISO would be approximately $65 million less over then years than the net benefit it could obtain by joining Southwest Power Pool. 2. Docket No. EO : AmerenUE s Application to Transfer Functional Control of its Transmission System to MISO On November 1, 2007, AmerenUE filed an application with the MoPSC to continue the transfer of functional control of its transmission system to MISO through April 30, SPP moved to intervene on November 21, 2007 and was granted intervenor status on December 4, On June 30, 2008, Ameren, MISO and the Missouri Industrial Energy Consumers submitted for MoPSC consideration and approval a Stipulation and Agreement to resolve all issues in this proceeding. Statements of Non-objection have been filed by Empire, Aquila, SPP and Kansas City Power and Light, respectively. On July 15, 2008, the MoPSC issued an order scheduling an on-the-record presentation for July 29, 2008 in Jefferson City, Missouri to allow the Commissioners an opportunity to question the parties about the Stipulation and Agreement of 68

73 On July 16, 2008, AmerenUE filed a motion to reschedule the on-the-record presentation in this docket for either August 5, 6 or 7, The MoPSC has not yet acted on this request. On September 9, 2008, an Order Approving Stipulation and Agreement was issued. Based on the Stipulation and Agreement, the Commission finds that AmerenUE s continued participation in Midwest ISO on an interim and conditional basis is not contrary to the public interest. T. New Mexico Regulatory Proceeding Case No UT: An Investigation into the Prudence of SPS Participation in the SPP RTO On October 16, 2007, the NMPRC issued an order docketing investigation into the prudence and reasonableness of SPS participation in the SPP RTO and requiring SPS to file direct testimony no later than 75 days after the completion of the SPS rate case, Case No UT. The hearing in the SPS rate case was completed on April 23, 2008, making SPS direct testimony in this case due July 7, On June 24, 2008, SPS filed an unopposed motion for an order extending the deadline for filings its direct testimony in this case. The NMPRC granted this request on June 25, 2008, extending the deadline from July 7, 2008 to July 31, SPS filed testimony July 31, On September 11-12, 2008, SPP met with the Public Regulation Commission and the Attorney General Office for educational purposes regarding the SPP RTO. On September 30, 2008, SPP filed a Motion for Leave to Intervene and Request for Discovery. A pre-hearing conference was held on October 1, Deadline to intervene is November 3, SPP is meeting with the New Mexico Public Regulation Commission on November 12, 2008, to provide more educational information regarding the SPP RTO. Staff and Intervenors Testimony is due February 3, Rebuttal Testimony is due March 6, A public hearing is scheduled for March 31, U. Texas Regulatory Proceedings 1. Docket No : Proceeding to Designate CREZs Senate Bill 20, enacted by the Texas Legislature in 2005, established targets in megawatts of renewable electric generation capacity in the State of Texas, and required of 68

74 the creation and designation of Competitive Renewable Energy Zones (CREZs) in areas of Texas where renewable energy resources and suitable land areas were sufficient to develop such renewable generation capacity. The PUCT opened a rulemaking docket to create and designate the first set of CREZs, Docket Number SPP filed a Motion to Intervene in that docket on January 22, That Motion was granted on January 25, SPP subsequently filed Direct Testimony and analyses performed by SPP of Transmission Alternatives for CREZs. An evidentiary hearing was held in the docket on June 11, SPP participated in that hearing, and the Commission issued an Interim Order on October 2, 2007, which designated CREZs, but specifically did not assign any of those CREZs to SPP. Commissioner Parsley, in her dissent, stated that the evidence clearly established that SPP was the appropriate region for delivery of the wind energy output from CREZ Zones 1 and 4, and that SPP provides the most beneficial and cost-effective delivery of energy from zones 1 and 4. As a result of the Commission s order, SPP, while still remaining a party to the docket, has not actively participated in the docket. In the October 2007 Order, the Commission ordered ERCOT to study and create transmission plans to accommodate four levels of wind generation ranging from 12 GW to 25 GW. In June, 2008, after conducting a Transmission Optimization Study with assistance from GE and filing additional testimony, the PUCT held a hearing to discuss the results of the study. ERCOT's Transmission Optimization study described two possible plans, A and B, for Scenario 1, (12 GW). Scenario 1B was the most popular of the two plans because of its expansion capability; it is estimated cost $3.78 billion. Scenario 3 (24.8 GW), had the highest cost estimate at $6.4 billion. Scenario 4, similar in capacity to Scenario 3, was the scenario requested by Commissioner Julie Parsley (which would have left the Panhandle wind generation with SPP) and involved a cost estimate of $5.75 billion. Many of the wind developers favored Scenario 3, while other participants, including Commission staff, supported Scenario 1B or Scenario 2 (18.5 GW), due to cost concerns (many fear ERCOT's estimates were understated) and/or concerns that much of the proposed wind generation might not actually be built. In addition to citing cost concerns, many parties criticized the GE study regarding ancillary services for its many limitations, which included the failure to identify specific impacts to ancillary services other than regulation and the failure to study wind penetration scenarios above 15 GW. As a result of the concerns cited by so many parties, the Commissioners apparently are no longer interested in the higher level wind scenarios. All were concerned about the reliability issues noted in the GE study and the criticisms of this study. Commissioner Parsley again urged support for allowing the Panhandle wind generation to stay with SPP. Commissioner Barry Smitherman specifically commented that he would not likely approve anything above Scenario 2. Now that parties have filed their final briefs, the Commissioners plan to spend the next two Open Meetings (July 17 and July 31) discussing the CREZ docket in more detail and will likely enter a final order shortly thereafter. SPP remains a party in this docket, but has not actively participated in the docket since the issuance of the October 2, 2007 PUCT Order of 68

75 2. Docket No : EGSI s Transition to Competition Plan On October 24, 2007, the PUCT issued an order abating the proceeding and instructing Entergy Gulf States (EGSI) to request SPP to conduct an analysis similar to that performed by ERCOT in their Phase II Entergy Integration Report and completed in SPP is in the process of conducting that analysis. The second, third and fourth SPP-ETI QPR stakeholder meetings were held in Austin, Texas on April 16 and June 20, September 16, 2008, respectively. The fifth stakeholder meeting is scheduled for November 11, SPP and ERCOT filed status reports in this proceeding on April 29, 2008 and anticipate filing another status report in the Fall of Docket No : SWEPCO Turk Plant CCN Proceeding A hearing on the merits was held May 29-30, Initial post-hearing briefs were due June 13, 2008, and reply briefs were due June 20, No order in the case has been issued. SPP is not a participant in this docket. 4. Docket No : Complaint of JD Wind against SPS On June 27, 2007, the JD Wind Companies filed a complaint with the Public Utility Commission of Texas requesting that it resolve a dispute between the JD Wind Companies and SPS regarding commercial terms for long-term written agreements for the sale of energy to SPS from any of the six wind farms. A hearing on the merits is scheduled for October 13-17, SPP is not an active participant in this docket. 5. Project No : Rulemaking Proceeding to Amend PUC Substantive Rules Relating to the Selection of Transmission Service Providers related to CREZs & Other Special Projects On June 19, 2008, the PUCT issued an order adopting new as approved at the May 22, 2008 Open Meeting), relating to Selection of Transmission Service Providers with changes to the proposed text as published in the December 21, 2007 issue of the Texas Register. SPP has not actively participated in this project of 68

76 Last Updated: October 20, 2008 Texas Kansas 08-ITCE-936-COC 08-ITCE-937-COC 08-ITCE-938-COC 08-PWTE-1022-COC Texas FERC RM05-17 RM05-25 Texas Arkansas U U U Kansas 08-ITCE-936-COC 08-ITCE-937-COC 08-ITCE-938-COC 08-PWTE-1022-COC Arkansas U U U Arkansas U U U Arkansas U FERC ER EL07-73 FERC RM06-22 REGULATORY OUTLOOK 2008 JD Wind s pre-filed rebuttal testimony due - Complaint of JD Wind against SPS (Order No. 8) ITC/Prairie Wind Dockets KCC Staff s Report and Recommendation Due (September 2, 2008 Order) Deadline for the completion of all discovery responses - Complaint of JD Wind against SPS (Order No. 8) RTO and ISO transmission providers, transmission providers whose facilities are in the footprint of an RTO or ISO, and WSPP to submit an FPA section 206 filing that contains the revised non-rate terms and conditions of the pro forma OATT as stated in Appendix B (Order 890-B at P 6; within 90 days of publication of this order in the Federal Register July 8, 2008) Hearing on the Merits on the Complaint of JD Wind against SPS Public Utility Commission of Texas, Austin, Texas (March 24, 2008 Order) Rebuttal Testimony by SWEPCO and SPP Due by Noon (August 5, 2008 Order Nos. 6, 5 and 2, respectively) ITC/Prairie Wind Dockets - Comments Due on Staff s Report and Recommendation (15 days from the filing of Staff s Report and Recommendation) Consecutive Public Comment Hearings APSC, Hearing Room 1 (August 5, 2008 Order Nos. 6, 5 and 2, respectively) Consecutive Evidentiary Hearings APSC, Hearing Room 1 (August 5, 2008 Order Nos. 6, 5 and 2, respectively) SPP to file the most recent ICT Quarterly Report and most recent monthly Market Monitoring Report (October 17, 2008 Order No. 2) SPP to provide a further status report regarding Violation Relaxation Limits (VRLs) Extended deadline for comments regarding FERC s proposal to close cyber security gap regarding U.S. nuclear plants not regulated by the Nuclear Regulatory Commission (October 10, 2008 Notice of Extension of Time) Oct. 2, 2008 Oct. 2, 2008 Oct. 6, 2008 Oct. 6, 2008 Oct , 2008 Oct. 17, 2008 Oct. 20, 2008 Oct. 27, 2008 Oct. 28, 2008 Oct. 30, 2008 Nov. 1, 2008 Nov. 3, 2008 D.C. Cir. Ct. of Appeals Respondent s Brief Due (July 16, 2008 Order) Nov. 3, of 68

77 Case No New Mexico UT FERC OA07-32 FERC ER Arkansas U Texas New Mexico UT Texas D.C. Cir. Ct. of Appeals Case No FERC RM05-17 RM05-25 FERC ER FERC TBD D.C. Cir. Ct. of Appeals Case No D.C. Cir.Ct. of Appeals Case No Arkansas U FERC ER FERC ER EL Entergy OA08-59 D.C. Cir. Ct. of Appeals Case No D.C. Cir.Ct. of Appeals Case No D.C. Cir.Ct. of Appeals Case No Deadline to file Motion to Intervene in the investigation into the Nov. 3, 2008 prudence of Southwestern Public Service Company s participation in the SPP RTO. Entergy s next Order 890 compliance filing is due. Nov. 4, 2008 SPP s compliance filing deadline for corrections to Bylaws Nov. 5, 2008 revisions. Deadline for any jurisdictional electric or natural gas utility to Nov. 7, 2008 comment and/or propose innovative approaches or methodologies (September 25, 2008 Order). Fifth SPP-ETI QPR stakeholder meeting Nov. 11, 2008 SPP to meet with the New Mexico Public Regulation Nov. 12, 2008 Commission to provide more educational information regarding the SPP RTO. SPP to file Study Report with PUCT Nov. 15, 2008 Intervenor for Respondent s Brief Due (July 16, 2008 Order) Nov. 18, 2008 Extended deadline for public utilities to develop, through Nov. 27, 2008 NAESB, business practices that support the revisions to NERC reliability standards MOD-001, MOD-008, MOD-028, MOD-029, and MOD-030 (November 21, 2008 deadline per the December 6, 2007 Extension of Time was extended by FERC on April 29, 2008) Deadline for The Empire District Electric Company to comply Dec. 1, 2008 with Attachment AI of SPP s Tariff SPP Tariff Cleanup filing to be made around Dec. 1 Dec. 1, 2008 Petitioner s Reply Brief Due (July 16, 2008 Order) Dec. 2, 2008 Appendix Due (July 16, 2008 Order) Dec. 9, 2008 Deadline to file comments in the Sustainable Energy Dec. 15, 2008 Resources (SER) docket pursuant to the October 7, 2008 Order. SPP s Compliance Filing due in the Balanced Economic Dec. 15, 2008 Portfolio Docket (October 16, 2008 Order) PJM to submit a report to FERC detailing its findings Dec. 15, 2008 regarding its Reliability Pricing Model (September 19, 2008 Order) Entergy Attachment K Compliance Filing due (September 18, Dec. 17, Order) Intervenor for Respondent s Final Brief Due (July 16, 2008 Dec. 23, 2008 Order) Petitioner s Final Reply Brief Due (July 16, 2008 Order) Dec. 23, 2008 Respondent s Final Brief Due (July 16, 2008 Order) Dec. 23, of 68

78 FERC SPP to file our 2009 Budget with FERC (due at end of year, Dec. 31, 2008 RT04-1, ER04-48 each year) 2009 FERC Deadline for Entergy to file a Software Development Progress Jan. 11, 2009 ER Report if the Weekly Procurement Process implementation filing is not made by then (October 10, 2008 Order) Arkansas SPP s briefing document due (October 17, 2008 Order No. 2) Jan. 15, U FERC Required Implementation Date WEQ-001 OASIS Standards Jan. 31, 2009 RM05-5 (Order 676-C) ER SPP Demand Response Status Report Due Feb. 1, 2009 New Mexico UT Staff and Intervenors Testimony Due in the investigation into the prudence of Southwestern Public Service Company s participation in the SPP RTO(October 3, 2008 Procedural Feb. 3, 2009 FERC OA08-61 FERC RM05-17 RM05-25 New Mexico UT New Mexico UT FERC Form 582 FERC ER FERC ER Kansas 08-KMOE-028-COC FERC ES07-40 FERC ER FERC ER Order) Compliance Filing Due on Attachment O Revisions for Coordinated and Regional Planning Process pursuant to the July 11, 2008 Order (October 9, 2008 deadline extended by FERC on September 12, 2008) Extended deadline for public utilities to develop, through NAESB, business practices that support the revisions to NERC reliability standard MOD-004 (April 29, 2008 Notice of Extension of Time) Rebuttal Testimony Due in the investigation into the prudence of Southwestern Public Service Company s participation in the SPP RTO (October 3, 2008 Procedural Schedule) Public Hearing in the investigation into the prudence of Southwestern Public Service Company s participation in the SPP RTO (October 3, 2008 Procedural Schedule) Feb. 6, 2009 Feb. 19, 2009 Mar. 6, 2009 Mar. 31, 2009 SPP FERC Form 582 is due Apr. 30, 2009 SPP Filing of Yearly Informational Report on SPP Aggregate Jul. 1, 2009 Study SPP Demand Response Status Report Due Aug. 1, 2009 Deadline for AECI to provide the KCC and the parties an update as to the progress of further agreement between AECI and SPP on congestion management and other issues; AECI/SPP Joint Operating Agreement dated August 12, 2008 (August 12, 2008 Order Approving Unanimous Settlement Agreement) Expiration of SPP s authorization to issue $50,000,000 in nonsecured promissory notes (August 15, 2007 Order) 2010 SPP to submit, twelve months after the effective date of SPP s proposal for external generator participation in the EIS Market (February 1, 2009), the External Market Monitor s evaluation (April 21, 2008 Order) SPP to submit, twelve months after the start of external generator participation in the EIS Market, an evaluation of the Aug. 12, 2009 Aug. 15, 2009 Feb. 1, 2010 Feb. 1, of 68

79 effectiveness of SPP s dispatch caps (April 21, 2008 Order) 4 63 of 68

80 SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT 3Q 2008 LEGAL MATTERS PENDING No Legal Matters Pending 64 of 68

81 EXECUTIVE INDUSTRY ACTIVITIES Executive Event Nick Brown FERC Technical Conference, Washington, D. C. (July 1) Kansas Corporation Commission Meeting, Little Rock (July 8) AECC Meeting, Little Rock (July 16) American Clean Coal Conference, Hope, AR (July 17-18) Governors Commission on Global Warming, Little Rock (July 31) EPRI Board, San Francisco (August 4-5) AECC Meeting, Little Rock (August 26) AR Public Service Commission, Little Rock, AR (September 5) Governors Commission on Global Warming, Little Rock (September 8-9) Platt s Conference, Baltimore, MD (September 15) Governors Commission on Global Warming, Little Rock (September 25) Missouri Public Service Commission, Jefferson City, MO (September 26) Oxy Meeting, Little Rock (September 29) Michael Desselle Kansas Corporation Commission Meeting, Little Rock (July 8) NERC MRC and Board Meetings, Montreal, CA (July 29-30) NAESB Meeting, San Diego, CA (August 12) WEQ EC Meeting, Colorado Springs, CO (August 19-20) NERC/NAESB Meeting, Houston, TX (August 28) NAESB Parliamentary Committee, Tampa, FL (September 3) NAESB Board of Directors Meeting, Houston, TX (September 25) Les Dillahunty Kansas Corporation Commission Meeting, Little Rock (July 8) SPP/ERCOT Meeting, Austin, TX (August 6) AR Public Service Commission, Little Rock, AR (September 5) New Mexico Public Regulation Commission, Santa Fe, NM (September 10-11) Meeting with NM Attorney General and Coops, Santa Fe, NM (September 12) Stacy Duckett Technical Conference with Nebraska Entities, Kansas City, MO (August 26) Women In Power Forum, Washington, DC, October 1 The Changing Landscape of Energy Law: Administrative Law Review Symposium, Washington, DC, October 2 Tom Dunn Kansas Corporation Commission Meeting, Little Rock (July 8) Meeting with AECC, Little Rock (July 16) Carl Monroe Kansas Corporation Commission Meeting, Little Rock (July 8) Executive Steering Committee for NE, Omaha, NE (July 9) LES/WAPA Meeting, Omaha, NE (July 10-11) 65 of 68

82 Basin/WAPA/SPP Meeting, Minneapolis, MN (July 21) NPPD/OPPD Meeting on Agreements, KC, MO (July 28) Western Farmers Board of Directors, Anadarko, OK (August 15) Southwestern Power Administration Meeting, Little Rock (August 20) Technical Conference with Nebraska Entities, Kansas City, MO (August 26) New Mexico Public Regulation Commission, Santa Fe, NM (September 10-11) Meeting with NM Attorney General and Coops, Santa Fe, NM (September 12) Cyber Security Summit, Washington, D. C. (September 23) City of Independence, MO (September 25) Missouri Public Service Commission, Jefferson City, MO (September 26) Lanny Nickell Kansas Corporation Commission Meeting, Little Rock (July 8) Southwestern Power Administration Meeting, Little Rock (August 20) OATI Management Forum (September 23) 66 of 68

83 WITHDRAWAL LETTERS SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT 3Q 2008 MEMBERS EFFECTIVE DATES Louisiana Energy & Power Authority 10/31/09 City of Lafayette Utilities System 10/31/08 MEMBERSHIP CHANGES Redbud Energy, LP transferred to Dogwood Energy, LLC 09/29/08 PENDING Lincoln Electric System Membership Agreement executed 09/22/08 (pending FERC approval) Nebraska Public Power District Membership Agreement executed 09/22/08 (pending FERC approval) Omaha Public Power District Membership Agreement executed 09/22/08 (pending FERC approval) 67 of 68

84 STAFFING REPORT SPP BOARD OF DIRECTORS EXECUTIVE QUARTERLY REPORT 3Q 2008 SPP Employee count as of January 1, 2008: 295 1Q New hires: 28 2Q New hires 31 3Q New hires 15 YTD Terminations: 0 Retired 26 Voluntarily terminated 1 Involuntarily terminated 2 Interns (part time/seasonal) 0 - Deceased 29 SPP Employee count as of March 31, 2008: 313 SPP Employee count as of June 30, SPP Employee count as of September 30, There are 345 full time employees in the 2008 budget. 68 of 68

85 Corporate Metrics Report September 2008 published October 21, 2008 produced by SPP Market Monitoring Unit 1 of 24

86 Southwest Power Pool Corporate Metrics Table of Contents Transmission & Market Indicators 1 Active transmission limit control indicators 2 Regional control performance 3 Transmission utilization proxy 4 EIS prices and price range 5 Congestion 6 Market liquidity Financial Metrics 7 SPP Admin Fee performance 8 Financial settlement index 9 Financial disputes index 10 Budget performance monitor Learning & Growth 11 Employee turnover Performance 12 Compliance with NERC Standards 13 IT System Performance 14 Metrics Definitions 2 of 24

87 1. Congestion 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 % of Breached Dispatch Intervals % of Binding Dispatch Intervals % of Congested Dispatch Intervals Transmission & Market Indicators % of Binding Dispatch Intervals % of Breached Dispatch Intervals % of Congested Dispatch Intervals 3,500 3,000 2,500 Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 60% 60% 61% 44% 25% 23% 72% 72% 48% 70% 77% 68% 42% 13% 2% 3% 1% 3% 4% 2% 3% 7% 11% 13% 10% 7% 67% 62% 62% 45% 28% 26% 74% 74% 52% 73% 80% 72% 45% Hours 2,000 1, GW curtailed 1, Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 TLR Time Binding & Breached Time Over Limit Time GW curtailed 0 in hours Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 TLR Time Binding & Breached Time Over Limit Time GW curtailed of 24

88 1. Congestion 3500 TLR by Level Hours in TLR Transmission & Market Indicators 0 Sep-07 Oct-07 Nov-07 Dec-07 Jan-08 Feb-08 Mar-08 in hours Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 Level 3A Level 3B Level 5A Level 5B Apr-08 May-08 Jun-08 Jul-08 Level 3A Level 3B Level 5A Level 5B Breakout of Level 5 TLR Events Aug-08 Sep Hours in TLR Sep-07 Oct-07 Nov-07 Dec-07 Jan-08 Level 5A Feb-08 Mar-08 Apr-08 May-08 Jun-08 Level 5B Jul-08 Aug-08 Sep-08 4 of 24

89 2. Regional Control Performance CPS1 Compliance # Balancing Authorities <100% 100%-150% >150% Transmission & Market Indicators Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 BA's with a CPS1 value of <100% are non-compliant CPS1 Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 >150% %-150% <100% Violation if any 1 Balancing Authority has a violation in a 12 month period. 5 of 24

90 2. Regional Control Performance 16 BA's with a CPS1 value of <100% are non-compliant CPS2 Compliance # Balancing Authorities <90% 90-95% >95% Transmission & Market Indicators Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 CPS2 Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 >95% % <90% of 24

91 3. Transmission Utilization Proxy $40,000 Transmission Utilization Indicators Transmission Revenues (Rolling 13 Month Averages) $35,000 Trans Revenue ($000s) $30,000 $25,000 $20,000 $15,000 $10,000 $5,000 Transmission & Market Indicators $0 Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 Network Firm PTP Non-Firm PTP Type Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 Network ($000) $22,308 $22,356 $24,798 $20,672 $23,732 $25,798 $25,068 $24,701 $24,756 $23,804 $23,284 $24,820 $28,415 Firm PTP ($000) $5,589 $5,509 $5,951 $5,657 $5,357 $5,752 $5,877 $6,033 $6,308 $6,363 $6,889 $6,506 $6,081 Non-Firm PTP ($000) $2,142 $2,557 $3,539 $2,996 $3,007 $3,055 $2,175 $2,261 $1,876 $2,010 $2,415 $2,473 $3,193 Transmission Utilization Indicators (MWh) MM MWh Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 Network Firm PTP Non-Firm PTP Type Network (MM MWh) Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep Firm PTP (MM MWh) Non-Firm PTP (MM MWh) Total of 24

92 4. EIS Prices and Price Range September 2008 $600 $600 $500 $500 $400 $400 $300 $300 Transmission & Market Indicators Prices ($/MWh) $200 $100 $0 $200 $100 $0 -$100 -$100 -$200 AECC AEPM EDEP GRDX GSEC KBPU KCPS KEPC KPP MIDW OGE OMPA SECI SPSM WFES WRGS Market Participant -$200 MP Max MP Min MP Average SPP Average = AECC AEPM EDEP GRDX GSEC KBPU KCPS KEPC KPP MIDW OGE OMPA SECI SPSM WFES WRGS MP Max MP Avg MP Min of 24

93 4. EIS Prices and Price Range 12 months from October 2007 through September 2008 Transmission & Market Indicators AECC AEPM EDEP GRDX GSEC KBPU KCPS KEPC KPP MIDW OGE OMPA SECI SPSM WFES WRGS MP Max MP Avg MP Min of 24

94 5. Congestion - Uplift $3,000 EIS Uplift $2,000 $1,000 $ Thousands $0 -$1,000 -$2,000 -$3,000 Transmission & Market Indicators -$4,000 -$5,000 -$6,000 Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 EIS Uplift ($000's) ,506-2,914-1,289-1,455-5,376-4,731-2,829-2,852 2, The RNU Task Force has been re-convened and is studying the reasons, and possible solutions, for the wide variation in RNU. The Task Force will also establish appropriate target ranges for RNU of 24

95 6. Market Liquidity 35,000 30,000 Market Liquidity 100% 90% 80% MW Offered (daily average) 25,000 20,000 15,000 10,000 5,000 70% 60% 50% 40% 30% 20% 10% % of Total Capacity Transmission & Market Indicators 0 Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 Dispatchable MW Total Offered MW % of Total Offered Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 Dispatchable MW 9,802 8,349 8,482 9,151 9,255 9,222 8,527 8,495 8,980 11,884 13,348 12,340 10,473 Total Offered MW 26,375 22,809 22,495 23,864 24,564 23,566 21,950 22,304 24,015 29,833 32,283 31,009 26,762 % of Total Offered 37% 37% 38% 38% 38% 39% 39% 38% 37% 40% 41% 40% 39% 60,000 50,000 EIS Market Sales Volumes (average daily volume by month) 0% $5,000 $4,500 $4,000 Sales MWh 40,000 30,000 20,000 10,000 $3,500 $3,000 $2,500 $2,000 $1,500 $1,000 $500 Sales ($000s) 0 Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 Avg Daily Sales (MWh) Avg Daily Sales ($) $0 Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 Avg Daily Sales (MWh) 41,230 32,204 34,747 34,325 33,541 31,372 35,581 40,661 40,499 50,812 54,867 51,848 41,435 Avg Daily Sales ($) 1,889 1,595 1,623 1,585 1,813 1,644 2,237 2,883 2,451 4,078 4,561 3,176 1, of 24

96 7. SPP Admin Fee Performance $0.22 Approved SPP Admin Fee $0.20 $ per MWh $0.18 $0.16 $0.14 $ Approved Admin Fee Budgeted NRR / Budget Load Actual NRR / Actual Load Financial Metrics Budgeted Net Revenue Required ($000's) $ 38,322 $ 44,391 $ 45,688 $ 52,819 $ 61,462 Budgeted Load (000's) 245, , , , ,496 Budgeted NRR / Budget Load $ $ $ $ $ Approved Admin Fee Actual Net Revenue Required ($000's) $ 33,443 $ 38,415 $ 49,549 $ 49,691 $ 44,565 Actual Load (000's) 245, , , , ,955 Actual NRR / Actual Load $ $ $ $ $ EIA-411 Load Growth Forecast -0.37% 3.05% -0.60% 1.80% 2.10% Actual Load Growth -1.60% 8.82% 7.19% 5.10% Note 1: Budgeted 2008 figures cover the entire 2008 calendar year, while actual 2008 figures cover the period through August 31, Note 2: Actual load growth for 2008 will not be calculated until year end. 12 of 24

97 8. Budget Performance Monitor $100, month Cumulative Operating Expense $90,000 $80,000 $70,000 Financial Metrics ($000's) $60,000 $50,000 $40,000 $30,000 $20,000 $10,000 $0 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 Actual Operating Expense Budgeted Operating Expense Cumulative Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 Actual Operating Expense ($000's) 7,299 14,255 21,233 27,858 35,936 43,225 51,223 58,268 66,633 74,383 82,911 91,235 Budgeted Operating Expense ($000's) 7,006 13,749 20,354 29,632 37,899 45,919 54,565 62,806 71,736 79,868 87,800 95,899 Variance: Fav / (Unf) (293) (506) (879) 1,774 1,963 2,694 3,342 4,538 5,103 5,485 4,889 4,664 % of Variance -4% -4% -4% 6% 5% 6% 6% 7% 7% 7% 6% 5% 13 of 24

98 9. Financial Settlement Index 20% Market and Transmission Billing Payments 26.0% 18% % of $ received after due date 16% 14% 12% 10% 8% 6% 4% 2% Financial Metrics 0% Sep- 07 Oct- 07 % of Transmission Payment $ Received After the Due Date % of Market Payment $ Received After the Due Date Nov- 07 Sep- 07 Dec- 07 Oct- 07 Nov- 07 Jan- 08 Dec- 07 Feb- 08 Transmission Billing Payments Jan- 08 Mar- 08 Feb- 08 Apr- 08 Mar % 2.3% 2.9% 0.1% 5.6% 0.3% 26.0% 3.2% 0.4% 4.7% 16.4% 5.9% 0.3% 0.0% 0.3% 0.7% 1.0% 0.0% 0.0% 0.3% 0.7% 0.0% 0.0% 0.1% 0.0% 0.9% May- 08 Apr- 08 Jun- 08 EIS Market Billing Payments May- 08 Jun- 08 Jul- 08 Jul- 08 Aug- 08 Aug- 08 Sep- 08 Sep- 08 Note: Figures represent billings with a due date in month shown. For example, the September figures are related to the August 31 transmission billing, with payments due on September of 24

99 10. Financial Disputes Index $500 Settlement Dispute Statistics ($) $400 $000's $300 $200 $100 $0 Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 Total Dispute Largest single dispute Avg. Dispute Size Financial Metrics (Figures in $000's) Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 Total Dispute $19.0 $55.7 $392.4 $141.2 $115.3 $28.6 $4.7 $68.7 $13.0 $5.0 $172.5 $469.7 $34.1 Avg. Dispute Size $.4 $.7 $19.6 $5.4 $2.5 $1.0 $.4 $2.0 $.4 $.3 $4.0 $8.9 $.8 Largest single dispute $1.3 $14.1 $186.0 $42.5 $27.6 $18.0 $1.2 $23.0 $4.4 $2.1 $159.2 $300.0 $13.3 Settlement Dispute Statistics # of Disputes Avg. Days Outstanding Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 # Disputes Avg Days Outstanding 0 Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 # Disputes Avg Days Outstanding of 24

100 11. Employee Turnover 2.0% Employee Turnover (monthly) 1.5% Turnover Rate 1.0% 0.5% 0.0% Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 Voluntary TO Rate Involuntary TO Rate Learning & Growth Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 Voluntary TO Rate 0.4% 1.0% 0.7% 0.7% 0.7% 1.3% 1.3% 1.5% 1.5% 0.9% 0.3% 0.3% 0.3% Involuntary TO Rate 0.0% 0.0% 0.3% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.3% Total Turnover (# of employees) % Rolling 12-month Turnover Rate 10% Turnover Rate 8% 6% 4% 2% 0% Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep 08 Rolling 12-month Turnover Rate Sep 07 Oct 07 Nov 07 Dec 07 Jan 08 Feb 08 Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep % 8.3% 8.1% 8.4% 8.6% 9.9% 9.7% 10.4% 10.8% 11.4% 10.6% 10.9% 11.1% 16 of 24

101 11. Employee Turnover 16% Annual Turnover Ratio and Employee Count % 350 Turnover Rate (annualized) 12% 10% 8% 6% 4% Total Employees 2% 50 Learning & Growth 0% * Total Employees Turnover Ratio (total) * Total Turnover Total Employees Turnover Ratio (total) 7.7% 2.2% 9.6% 6.4% 9.1% 6.9% 6.1% 4.7% 5.7% 7.1% 10.6% Note 1: Total Turnover only includes voluntary and involuntary separations; retirements and interns are not used in the calculation. * 2008 figures are as of the end of the reported month, and extrapolated to a full-year equivalent. 17 of 24

102 12. Compliance with NERC Standards SPP RTO Compliance Sep 07 Oct 07 Nov 07 # Confirmed Violations Dec 07 Jan 08 Feb 08 Mar 08 Apr May 08 Jun 08 Jul 08 Aug 08 Sep SPP Registered Entity Compliance Sep 07 Oct 07 Nov 07 # Confirmed Violations Dec 07 Jan 08 Feb Mar 08 Apr 08 May 08 Jun 08 Jul 08 Aug 08 Sep Performance 18 of 24

103 13. IT System Performance System Availability for September 2008 System Unplanned Outages Minutes Market System (MOS) Target Uptime Actual Uptime Resulting Market Outage Y Comments 9/3/08 & 9/30/08, see below under "Overall EIS Market Status" Market Portal N Reliability (EMS) Y 9/30/08 75 minute EMS outage that resulted from network problems that were caused by improper firewall monitoring activities. Corrective action has been taken to prevent recurrence. Reliability (ICCP) N Performance Tariff Admin (OASIS) Scheduling (RTO_SS) N N * Target Uptime is calculated to be not more than 10 minutes of unplanned outages per month. Overall EIS Market Status 2 UNPLANNED MARKET OUTAGES FOR SEPTEMBER 2008 The first outage (9/3) was a 290-minute suspension of market activities due to an SPP Market Participant being unable to submit data following model changes implemented by SPP staff. Corrective action is being taken to prevent future data submission issues from causing a market suspension. The second outage (9/30) involved multiple system outages that resulted when firewall monitoring activities caused network failures. Corrective action has been taken to prevent recurrence. 19 of 24

104 13. IT System Performance System Availability Trends System Sep-07 Oct-07 Nov-07 Dec-07 Jan-08 Feb-08 Mar-08 Apr-08 May-08 Jun-08 Jul-08 Aug-08 Sep-08 Market System (MOS) Market Portal Reliability (EMS) Reliability (ICCP) Tariff Admin (OASIS) Performance Scheduling (RTO_SS) No unplanned outages less than 10 minutes unplanned outages 10 minutes or more unplanned outages 20 of 24

105 Southwest Power Pool Metrics Definitions Summary of Regional Operational Performance Indicators Two groups of metrics will be monitored to provide an overall health indication of the regional transmission system and market. There are two primary areas of interest: Reliability Performance Indicators, which focus on the actual operations of the transmission system and whether or not it was operated within expected limits and standards. Market Performance Indicators, which focus on the performance of the market in terms of overall volume, prices and level of participation. The intent is to monitor the trends in these areas over time to identify any unexpected performance in an area. Specific performance targets may be established in the future as experience is gained with the information. Transmission & Market Indicators Purpose of Reliability Performance Indicators This sub-group of metrics is designed to measure the operations of the transmission system from a reliability perspective in the prior 12 month period. Together, they form an aggregate representation to answer the following questions: Were any operating limits violated in the period? (see Congestion) How long were schedules curtailed due to congestion? (see Congestion) Was the system operated in compliance with the relevant control performance standards? (see Regional Control Performance) Provides a set of measures on the number of minutes control actions are taken to reduce the flow on one or more facilities below its System Operating Limit (SOL) or IROL limit. Percent of intervals binding (flow = SOL), breached (flow >SOL) and congested (either binding or breached) during the month. Time (in hours) during the month that flowgates were in TLR, Congested or Over the Limit. TLR Time is the total period of time that the Reliability Coordinator (RC) issued a Transmission Loading Relief (TLR). 1. Congestion Binding/Breached Time is the the total period of time that the Security Constrained Economic Dispatch (SCED) engine was redispatching out of its normal economic order to relieve constraints on the system. Over Limit Time is the total period of time that any real-time postcontingent flowgate flow was over the set rating of the flowgate. GW curtailed is the number of GW curtailed using either schedules or market flow during TLR events. TLR Events by level (in hours) Level 3 - curtailment of some non-firm schedules and market flow Level 5 - curtailment of some non-firm and firm schedules and market flow "A" Levels begin curtailing at the beginning of the next hour "B" Levels begin curtailing immediately and lasts through the end of the next hour Figures will be reported on a rolling thirteen month basis to allow comparison to prior seasons and similar months. 21 of 24

106 Transmission & Market Indicators 2. Regional Control Performance Measures the aggregate performance to the NERC CPS (Control Performance Standards) of the Balancing Authorities in the region. This indicator is set based on the number of BAs within region that are in compliance with the NERC real time control performance standards (known as BAL-001 Real Power Balancing Control Performance and BAL-002 Disturbance Control Performance). CPS1 requires BAs to be in compliance for 100% of the periods measured within the month; and CPS2 requires BAs to be in compliance for 90% of the periods measured within the month. For the CPS1 standard, each BA s rolling 12 month performance is grouped into one of three performance bands (<100% [red], % [yellow], >150% [green]). The number of BA s whose CPS1 score falls into these bands is shown; with below 100% meaning non-compliant with the standard. CPS2 performance is depicted in the appropriate bands (<90% [red], 90-95% [yellow], >95% [green]) based on the monthly CPS2 score rather than a rolling 12 month average. This sub-group of indicators provides a view of the effectiveness of the EIS market in the context of answering the following questions: What was the value of transmission services used in the month? (see Transmission Utilization) What was the average wholesale price paid in the region and what was its volatility? (see Price and Price Range) How much of the total congestion could be resolved through market mechanisms? (see Congestion Resolved by Market) What was the level of available generation offered to the market and EIS related energy sales in the month? (see Market Liquidity) 3. Transmission Utilization 4. Price and Price Ranges 5. Congestion - Uplift Measures the volume of transmission service scheduled in the month in terms of the transmission service revenues paid by both Network Customers and Point-to-Point customers. The revenues paid by transmission customers are directly related to the amount of transactions scheduled on the transmission system and therefore provide a proxy as to the utilization of the transmission system in the period. The figure reported will be a simple sum of the transmission service revenues paid for Network Service, Firm Point-to-Point, and Non-Firm Point-to-Point transmission service. Figures will be reported on a rolling thirteen month basis to allow comparison to prior seasons and similar months. Shows the EIS market prices for each market participant within the footprint on both a 12-month rolling average and for the previous month. It provides a summary of the average, high and low prices in each period. Tracks amount of RNU (Revenue Neutrality Uplift) charged or credited to market participants during the month. RNU ensures settlement payments/receipts for each hourly settlement interval equal zero. Positive RNU - SPP receives insufficent revenue and "owes" market participants. Negative RNU - SPP receives excess revenue, which must be credited back to market participants. RNU Task Force has been re-convened to look at wide variation in monthly RNU. 22 of 24

107 Transmission & Market Indicators 6. Market Liquidity Measures the average daily MW capacity offered to the EIS market (dispatchable generation); presented as a percent of daily average capacity available in the hour. Data was taken from the Resource Plans. Average daily MWh sales into the EIS Market and their dollar value are shown as well. Although no specific performance targets have been set, the intent is to monitor the trend of this index to identify significant deviations from average. Purpose of Financial Metrics This group of metrics provides a view of the organization s overall financial situation in terms of both the operating costs and settlement functions carried out. 7. SPP Admin Fee Performance (Rolling) Measures actual costs incurred by SPP on an annual basis and compares this to the approved Admin Fee and Budgeted Net Revenue Requirement (NRR). Financial Metrics 8 9 Budget Performance Monitor Financial Settlement Index Measures the total actual operating expenses against the total budgeted operating expenses across the organization. Metric measures the timeliness of the financial settlements for both transmission billing and EIS market billing and provides a proxy for the strength of the organization s cash flow. 10 Financial Disputes Index Measures the number and value of disputes made with regards to the financial settlements of the markets. The objective in this area is twofold: (1) minimize the time to clear disputes; and (2) minimize the total value of dollars in dispute. The monthly indicators are the following three variables: Total number of disputes Total dollars in dispute Average # days to resolve disputes Learning & Growth Purpose of Learning & Growth Metrics These indicators provide insights to the organization s success in maintaining and supporting its desired staffing levels and employee growth plans. 11. Employee Turnover Measures both involuntary and voluntary turnover rates in the organization. Monthly turnover is charted on a rolling 12 month basis, while annual turnover ratio and number of employees is provided for historical purposes. 23 of 24

108 Performance Purpose of Performance Metrics These Performance Metrics are divided into two categories, quarterly and annual, which describe the frequency with which they will be monitored. The metrics in this group focus on compliance and achievement of major initiatives. Only the NERC Compliance and IT System Availability metrics are reported as part of the Metrics Report document. The other measures in this category will be reported on a periodic basis in separate reports. 12. NERC Compliance Measures SPP s compliance with all NERC standards. Status is green unless there is a self-reported violation of any criteria during the period. This metric excludes the control performance standards which are included in the Regional Control Performance metric. 13 IT System Availability Measures availability of SPP IT Systems. Target uptime for all systems is calculated to be not more than 10 minutes of unplanned outage per month. However, 100% availability is always the ultimate goal. Boxes showing green represent 100% actual uptime; yellow represents less than 100% uptime but under 10 minutes of unplanned outage; while red represents 10 minutes or more of unplanned outage. 24 of 24

109 SPP.org 1 Energy Efficiency & Demand Response Is the question still Simply check off the task, or take meaningful action?

110 The Commission s Order and SPP Compliance FERC s September 26, 2006 Order on SPP s EIS docket SPP shall coordinate with utilities, state commissioners and other interested parties to consider provisions for participation of demand resources in the imbalance market. Further, FERC required a compliance filing concerning demand response within six months of the Order and reports every six months thereafter. SPP Compliance and Future Reports SPP provided Compliance Filings to FERC on March 20, 2007, August 1, 2007, and February 4, 2008 SPP provided a status report on August 13, 2008 and will continue to provide Demand Response status reports to FERC every six months SPP.org 3 SPP Demand Response Activities Update The DRTF proposed Market Protocol and Tariff language supporting changes to the Market Protocols to incorporate demand response in the EIS Market (PRR176). The Tariff language will be presented in the October 2008 SPP Board of Director s meeting for consideration. The RSC Demand Response Educational Forum held on July 27-28, 2008 The Lawrence Berkeley National Laboratory performed a Demand Response Survey for SPP. SPP continues to partner with the ISO/RTO Council, EPRI, and the United States Demand Response Coordinating Committee in Demand Response Initiatives. Demand response is being carefully considered in analysis of possible future day-ahead energy and ancillary services markets. SPP.org 4

111 Federal, State, and Company Initiatives Federal initiatives are growing Order 719 National Action Plan for Demand Response State initiatives are developing Arkansas PSC has recently opened three dockets which have focus on Demand Response. Kansas CC hosted an Energy Efficiency Workshop in August. Member Initiatives are developing OG&E announced it would begin Positive Energy SmartPower, a smart technology pilot program to deploy smart meters in 6,600 homes in Oklahoma City. NARUC supports demand response initiatives for states SPP.org 5 Excerpts from FERC Final Rule Wholesale Competition in Regions with Organized Electric Markets Paragraph 164 With regard to SPP s comment that there is no retail access state within SPP, the Commission notes that its ARC (aggregator of retail customers) requirements are not limited to aggregation of retail customers who have retail choice... Nor will we decide whether a regulator of a traditional, vertically-integrated monopoly utility may give permission for an ARC to aggregate customers demand responses for bidding into SPP s markets SPP.org 6

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113 1 of 90 Southwest Power Pool BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING Intercontinental Hotel at the Plaza, Kansas City, MO July 29, Summary of Action Items - 1. Approved Consent Agenda items: a. The minutes from the April 22, 2008 Board of Directors/Members Committee meeting. b. The Markets and Operations Policy Committee s recommendations to approve: 1. Kansas Power Pool waiver for such amount up to $12,819,426 of Base Plan funding. 2. Northeast Texas Electric Cooperative waiver for such amount to fully Base Plan fund the project. 3. Kansas Electric Power Cooperative waiver for such amount to fully Base Plan fund the project. 4. Tariff modifications regarding PRR Modifications to Criteria Modifications to Criteria Notifications to Construct authorizations for the seven projects listed in the Board background materials as MOPC Item 12 upgrade cancellations. pdf. 8. Reclassification of the Plymell to Pioneer Tap project to reliability and inclusion in Appendix B of the 2007 STEP qualifying for base plan funding. 10. SPP Staff s proposed interim Aggregate Study Tariff language and authorize the Staff and/or RTWG to make non-substantive changes to the Tariff language prior to filing with FERC. c. Approved the Finance Committee recommendations: 1. To engage BKD to perform an audit of SPP s 2008 financial statements and results. 2. To engage PricewaterhouseCoopers to perform an audit of SPP s 2009 controls environment. d. Approved Human Resources Committee s recommendation to approve the amended pension plan document and direct SPP to file the amended and restated pension plan document with the IRS. 2. Approved the Corporate Governance Committee s recommendation to insert Section 2.5 Participation in Regional Entity Activities in the SPP Bylaws. 1 1 of 90

114 2 of 90 SPP Board of Directors/Members Committee Minutes July 29, Approved the Markets and Operations Policy Committee s recommendation to approve Tariff language for the newly created Schedule Approved the Markets and Operations Policy Committee s recommendation to approve Tariff changes allowing the RTWG to make any non-substantive changes to the Tariff language necessary to implement the concepts set out in the RSC Concepts Paper on Economic Upgrades. 5. Approved the Markets and Operations Policy Committee s recommendation that SPP file PRR 165 Tariff modifications with FERC with a transmittal letter stating issues that need resolution for John Deere Wind Energy. 6. Approved the Markets and Operations Policy Committee s recommendation to approve Tariff language for incorporation into the SPP OATT necessary to implement PRR Approved the Markets and Operations Policy Committee s recommendation to approve the MOPC reorganization: Moving the responsibilities of the Operations Model Development WG, Operations Data WG, and Operations Training WG to the Operating Reliability WG Moving the responsibilities of the Model Development WG to the Transmission WG 8. Approved the Markets and Operations Policy Committee s recommendation to endorse the inclusion of OG&E s Woodward-Northwest 345kV project in the approved 2007 STEP as a sponsored project. 9. Approved the Finance Committee s recommendation to approve the 2008 Contract Services Budget with increased staffing resources to 13 direct staff; increased expenses totaling $1,997,000; increased revenue totaling $3,235,000; and continued work to reduce liability exposure. 10. Approved the Finance Committee s recommendation to approve a seven year lease on an aircraft with several requirements pending review of final agreements. 2 2 of 90

115 3 of 90 MINUTES NO. 118 Southwest Power Pool BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING Intercontinental Hotel at the Plaza, Kansas City, MO July 29, 2008 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. Julian Brix, director Mr. Nick Brown, director Mr. Jim Eckelberger, director Ms. Trudy Harper, Tenaska Power Services Company Mr. John Olsen, for Mr. Kelly Harrison, Westar Energy Ms. Cindy Holman, Oklahoma Municipal Power Authority Mr. Rob Janssen, Redbud Energy Mr. Jeff Knottek, City Utilities of Springfield Mr. Joshua Martin, director Mr. Steve Parr, Kansas Electric Power Cooperative Mr. Mel Perkins, OG+E Electric Services Mr. Mitch Williams, for 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. David Brian, for Mr. Rick Tyler, Northeast Texas Electric Cooperative Mr. Gary Voigt, Arkansas Electric Cooperative Company Mr. Rick Wolfinger, Constellation Power Source Mr. Eckelberger asked for a round of introductions. There were 74 persons in attendance either in person or via phone representing 21 members (Attendance List - Attachment 1). Mr. Brown reported proxies and a quorum was declared (Proxies - Attachment 2). Mr. Eckelberger welcomed guests from the Nebraska entities and Associated Electric Cooperative. He announced that there would be an executive session immediately following the meeting for the Board of Directors and Members Committee. Agenda Item 2 Pending Action Items Report Ms. Stacy Duckett reviewed past action items (Past Action Items Attachment 3). Agenda Item 3 President s Report Mr. Nick Brown presented a resolution for Ms. Julie Parsley to recognize her fine leadership and service on the Regional State Committee (RSC). Ms. Parsley was a founding member of the RSC and served as President for two years. Ms. Parsley has resigned her position on the Public Utility Commission of Texas effective in September Mr. Brown moved that the Board adopt this resolution. Mr. Harry Skilton seconded the motion which passed by acclamation. Mr. Brown called attention to the Metrics Reports (old and new formats) in the background material and stated that Mr. Carl Monroe would provide a review of the Corporate Metrics later in the meeting (Metrics and Quarterly Report Attachment 4). Mr. Brown then presented the President s Report which included: 3 3 of 90

116 4 of 90 SPP Board of Directors/Members Committee Minutes July 29, 2008 The Government Accounting Office (GAO) has completed its audit of SPP. The comments were positive. The final report is expected in August and will be posted 30 days after being issued. PricewaterhouseCoopers completed Phase I of the Type II SAS 70 audit noting no exceptions. Mr. Brown spoke at a Regional Clean Coal Technical Conference in Hope, AR. This was a great opportunity with legislators attending from multiple states. An exit interview for the Regional Entity portion of the FERC audit has taken place. Comments were that there is not enough separation between the RTO and the RE. Five recommendations were made to enhance separation of which some would change the SPP model. This will be further discussed following receipt of the report. Action is pending by the Kansas Corporation Commission on a settlement agreement between Associated Electric Cooperative (AECI) and Southwest Power Pool which would require AECI to execute a Joint Operating Agreement with SPP as a condition of its certification in Docket No. 08-KMOE-028-COC. SPP expenses year to date are up but are still below budget due to Balancing Authority personnel not yet hired. The repayment of the $25 million note was completed in March Mr. Les Dillahunty provided a written report on SPP s Generator Interconnection Queue and Aggregate Studies process (GI & AS report Attachment 5). Mr. Carl Monroe reviewed the Corporate Metrics report and entertained questions. The directors commented that this report is very worthwhile in providing data. It was suggested that receiving this data earlier would be helpful in order to formulate questions. Agenda Item 4 Regional State Committee Report Vice President David King presented the Regional State Committee (RSC) report. He noted that the RSC also approved the resolution commending President Julie Parsley for her service and leadership on the Regional State Committee. Mr. King stated that the Demand Response Forum held on July 27 and 28 was beneficial to all attending. He was delighted that Mr. Tim Texel of the Nebraska Power Review Board participated in the RSC meeting. The RSC met July 28 with an agenda that included reports, updates and discussion on the following items: The RSC heard reports from officers, SPP, FERC and the RE. Mr. Michael Desselle (SPP) provided an update on the SPP Strategic Plan. Mr. Casey Cathey (SPP) reviewed input assumptions of the Cost Benefit Task Force for the future markets study. Approved waivers for Kansas Electric Power Co., Northeast Texas Electric Cooperative and Kansas Power Pool. Approved Tariff language for cost allocation for economic upgrades and the balanced portfolio. Commissioner Moffet commended the SPP Staff and the Cost Allocation Working Group for their work as well as the people who crafted the Tariff language. The RSC also discussed the economic evaluation for the EHV Overlay, which is a critical issue. Agenda Item 5 Federal Energy Regulatory Commission Report Mr. Robert Ivanauskas provided an update on FERC activities. At the July open meeting, the Commission: Set for hearing whether certain natural gas futures trading activities by Amaranth Advisors LLC violated the Commission s anti-manipulation regulations. Additionally, the Commission reiterated that it has jurisdiction under the NGA to impose penalties for manipulative trading of NYMEX natural gas futures contracts that have a clear and direct effect on physical jurisdictional natural gas sales prices. 4 4 of 90

117 5 of 90 SPP Board of Directors/Members Committee Minutes July 29, 2008 Approved modifications to strengthen previously approved reliability standards. Specifically, the Commission approved modifications to five approved reliability standards involving interchange scheduling and coordination. The Commission directed NERC to further explain a sixth standard involving transmission loading relief procedures. Also in July by delegated letter order, the Director of OEMR Central accepted a requested change in the effective date for participation by external generators in SPP s Energy Imbalance Market to become effective on or before February 1, Finally, in early July, the Commission convened a conference in order to review wholesale power markets in various regions of the country. SPP was an active participant in this conference. At the June open meeting, the Commission: Largely reaffirmed its rule on open access transmission issued in 2007 and later in its rehearing order. The Orders in 890, 890-A and 890-B are intended to strengthen and correct flaws by reforming the terms and conditions of the Open Access Transmission Tariff. Also, the Commission reviewed a staff report on increasing costs in electric markets. The report focused on the rising cost of natural gas and concluded that this will continue in the future but could be mitigated by measures such as demand response, energy efficiency and conservation and technological innovations. Also in June the Commission accepted Midwest ISO s proposed reliability service and seams coordination service for non-members in the MAPP region. The Commission, however, required additional information on Midwest ISO s proposal to extend market services to entities that are non-signatories to the Midwest ISO Transmission Owners Agreement. At the May open meeting, the Commission: Unveiled a package of reforms to strengthen its enforcement programs. The package included an expanded policy statement on enforcement; an interpretative order that expands the areas in which the Commission will allow the no-action letter process; a Notice of Proposed Rulemaking that clarifies off-the-record contacts and separation of functions in the context of enforcement investigations; and a final rule that outlines the rights of entities against whom staff from the Office of Enforcement seeks an order to show cause. Also in May, the Commission accepted in part and rejected in part SPP s filing to, among other things, revise its transmission aggregate study process. Other FERC events: Senior staff from the Office of Energy Market Regulation (OEMR) continue their participation in ongoing outreach to the state commissions covered under classic SPP RTO as well as the SPP ICT arrangement with Entergy and the SPP ITO arrangement with EON. Finally, OEMR Central Director, Penny Murrell plans to attend the October SPP meetings in Tulsa. Agenda Item 6 Regional Entity Trustee Report Mr. Gerry Burrows provided a report on the Regional Entity (RE) Trustees activities. Mr. Burrows stated that the RE has now been in existence for one year. He credited its success to the RE Staff. The RE functions and activities are: Mitigations are complete for all violations prior to June 18, 2007, the date mandatory standards 5 5 of 90

118 6 of 90 SPP Board of Directors/Members Committee Minutes July 29, 2008 went into effect, with the exception of one which will be complete in December There are 1473 alleged enforceable violations post June 18, 2007 which are not completed. Registered Entities within the SPP RE footprint have 53 enforceable violations in process; 20 are documentation related and 33 are not. NERC has listed the top eleven Standards with the most violations, with sabotage topping the list. RE compliance workshops are held twice per year. The SPP RE Fall Compliance Workshop is scheduled for September 23 and 24 in Tulsa, Oklahoma. Compliance audits for 2008 are on schedule. The SPP RE endorses the approval of modified Criteria 11 as approved by the MOPC on July 15, The SPP RE will use this as a reporting procedure for all registered entities within the SPP RE footprint in order to meet the requirements of NERC Standard EOP-004. Agenda Item 7 Consent Agenda Mr. Eckelberger presented the following consent agenda items for approval (Consent Agenda Attachment 6): A. Approve April 22, 2008 Board of Director/Members Committee meeting minutes. B. Approve Markets and Operations Policy Committee s (MOPC) recommendations: 1. Kansas Power Pool waiver for such amount up to $12,819,426 of Base Plan funding. 2. Northeast Texas Electric Cooperative waiver for such amount to fully Base Plan fund the project. 3. Kansas Electric Power Cooperative waiver for such amount to fully Base Plan fund the project. 4. Tariff modifications regarding PRR Modifications to Criteria Modifications to Criteria To cancel Notifications To Construct authorizations for the seven projects listed in the Board background materials as MOPC Item 12 upgrade cancellations.pdf 8. Reclassification of the Plymell to Pioneer Tap project to reliability and inclusion in Appendix B of the 2007 STEP qualifying for base plan funding. 9. Inclusion of OGE s Northwest Woodward 345 kv project in the approved 2007 STEP as a sponsored project. 10. SPP Staff s proposed interim Aggregate Study Tariff language and authorize the Staff and/or RTWG to make non-substantive changes to the Tariff Language prior to filing it with FERC. 6 6 of 90

119 7 of 90 SPP Board of Directors/Members Committee Minutes July 29, 2008 B. Approve Finance Committees recommendations to: 1. Engage BKD to perform an audit of SPP s 2008 financial statements and results. 2. Engage PWC to perform an audit of SPP s 2009 controls environment. C. Approve Human Resources Committee s recommendation to approve the amended pension plan document and direct SPP to file the amended and restated pension plan document with the IRS. Mr. Eckelberger asked for requests to remove any items from the Consent Agenda or a motion to approve. Mr. Carl Huslig requested that Item B9 of the MOPC recommendations regarding OG&E s Northwest- Woodward 345kV project be added to MOPC s regular agenda items. Mr. Stuart Solomon said that he would abstain from voting on Item B10 of the MOPC recommendations regarding the Aggregate Study Tariff language explaining that he recognizes the problem but that AEP has four different RFP s that this item would impact. Mr. Solomon encouraged the Board to have continued focus on the Aggregate Study effort. Mr. John Olsen said that Westar would also abstain from voting for Item B10. Mr. Steve Parr said he would abstain voting on Item B3, Kansas Electric Power Company s waiver request. Mr. Julian Brix moved to approve the consent agenda items with Item B9 of the MOPC recommendations to be moved to the regular agenda. Mr. Josh Martin seconded the motion. The Members Committee voted in favor with the previous mentioned abstentions. The motion passed. Agenda Item 8 Corporate Governance Committee Report Mr. Nick Brown provided the Corporate Governance Committee report (CGC Report Attachment 7). Mr. Brown stated that SPP was approved by FERC to serve as a Regional Entity under NERC. This approval has required subsequent compliance filings. The most recent order (issued in March) requires SPP to modify its Bylaws to make clear that membership in the Regional Entity is open to any entity and that SPP will not charge a fee for such participation. The SPP Staff proposed the addition of a new Section 2.5 under Section 2.0 Membership as follows: 2.5 Participation in Regional Entity Activities Participation in SPP Regional Entity activities is open to the public and does not require membership in SPP, Inc. nor any of the obligations of membership, including SPP, Inc. s annual fee. Mr. Brown moved that the Board of Directors approve insertion of the new Section 2.5 Participation in Regional Entity Activities in the SPP Bylaws. Mr. Larry Altenbaumer seconded the motion. The Members Committee was in unanimous favor. The motion passed. Mr. Brown reported that Nebraska entities have proposed a modification to the SPP Bylaws expanding the state/federal power agencies represented on the Members Committee from one to two representatives. In order to meet filing deadlines for the Bylaws modifications, a Special Meeting of Members teleconference is tentatively scheduled for September 8 in order to approve requirements to integrate Nebraska entities into SPP. SPP Membership Agreement changes and Tariff language will be addressed at the September 8 meeting as well. MOPC will need to schedule a special meeting to review the Regional Tariff Working Group Tariff language. The Annual SPP Organizational Groups Chairs and Secretaries meeting has been scheduled for November 20 and 21 in Little Rock at the SPP Offices. Mr. Mike Palmer (Empire District) asked if the SPP voting structure had been discussed. It has not but is on the to do list. 7 7 of 90

120 8 of 90 SPP Board of Directors/Members Committee Minutes July 29, 2008 Agenda Item 9 Oversight Committee Report Mr. Josh Martin presented the Oversight Committee Report. The Committee met in Chicago on June 25. This was Mr. Julian Brix s first meeting with the Committee. Mr. Larry Altenbaumer attended as well. The following items were discussed: NERC has issued the final report for the on-site readiness evaluation of the Southwest Power Pool Reliability Coordinator (SPP RC) that was conducted in February. SPP is awaiting NERC action as to whether the SPP Training Program will be voted an Example of Excellence. Mr. Richard Dillon and Mr. Craig Roach presented the 2007 State of the Market report to FERC staff on June 3. FERC staff was pleased with the report and responded very positively to the Benefits Analysis. The Committee has asked Mr. Dillon and Mr. Roach to consider whether other pertinent data points may be available from these reports and/or whether these reports could serve as a basis for assessing additional benefits from current or future market designs. NERC recently issued its first series of compliance violations since mandatory standards went into effect. Most of the violations were related to documentation and did not carry a fine this time. There was one SPP Registered Entity that was cited, but not fined. This resulted from a self-report related to documentation requirements. FERC continues to issue civil penalties for tariff violations as well. The Oversight Committee s next scheduled meeting is September 25 in Hilton Head, SC. Agenda Item 10 Markets and Operations Committee Report Mr. John Olsen provided the Markets and Operations Policy Committee Report (MOPC Recommendations & Presentation Attachment 8). Mr. Olsen presented the following action items for approval: Schedule 13: Schedule 13 is for compliance with FERC s requirement that Independent Power Producers (IPP s) can self-supply station power; allows the Generator to take power under the EIS Market; Generation Owners can decide not to use Schedule 13; does not require any party in SPP to change its current method of procuring station power; and is an added customer selection of the use of Schedule 13 to the generation interconnection form in Attachment V. MOPC recommended that the Board of Directors approve the Tariff language for the newly created Schedule 13. Mr. Nick Brown moved to approve and Ms. Phyllis Bernard seconded the motion. The Members Committee was in unanimous favor. The motion passed. Tariff Modifications to Implement RSC Concepts Paper on Economic Upgrades: One or more potential Balanced Portfolios will be developed using the process, as outlined in the RSC Concepts Paper, using stakeholder input. The RTWG and MOPC have approved Tariff changes to implement concepts set out in the RSC Concepts Paper on Economic Upgrades. These changes have also been reviewed by Wright & Talisman. MOPC recommended that the Board of Directors approve the attached Tariff changes allowing the RTWG to make any non-substantive changes to the Tariff language necessary for filing at the Commission. Mr. Larry Altenbaumer moved to approve. Mr. Harry Skilton seconded the motion. The Members Committee was in unanimous favor. The motion passed. Mr. Tim Woolley wanted the group to clarify that this did not include the EHV Overlay projects. Mr. Eckelberger suggested that the Business Practices Working Group (BPWG) check the process. The group praised Ms. Pam Kozlowski for her guidance to RTWG. 8 8 of 90

121 9 of 90 SPP Board of Directors/Members Committee Minutes July 29, 2008 Tariff Modifications for PRR 165: FERC noted that SPP did not have language allowing unexecuted agreements for generation registration to be filed with FERC and suggested a filing be made. Generators must be appropriately accounted for in the SPP market footprint for reliability and accounting purposes. The approved language requires registration of all generation, including behind the meter down to 10 MW. Concerns expressed were: is this the appropriate minimum for behind the meter generation units, and PURPA implications. MOPC recommended that the Board of Directors approve the revised Tariff language for incorporation into the SPP OATT necessary to implement PRR 165. Mr. John Harvey of John Deere Wind Energy stated that he does not object to registering but feels it needs to happen in the right way so as not to deny statutory and rule based rights. Following much discussion regarding legalities and compliance with PURPA, Mr. Jeff DiSciullo of Wright & Talisman was consulted. Mr. DiSciullo stated that it was within SPP s legal rights to file the Tariff modifications for PRR 165 and that FERC would have to consider any issues related to PURPA rights or conflicts with state law. Ms. Phyllis Bernard moved that SPP file PRR 165 Tariff modifications with FERC and include in the transmittal letter the types of issues raised by the John Deere Wind Energy situation for the Commission s consideration. Mr. Nick Brown seconded the motion. The Members Committee was in favor with Mr. Rick Wolfinger abstaining. The motion passed. Tariff Modifications for PRR 141: These modifications are to include more accurate details concerning registration changes and the timing necessary to ensure good utility practices are applied when making registration/model updates. MOPC recommended that the Board of Directors approve the revised Tariff language for incorporation into the SPP OATT necessary to implement PRR 141. Mr. Nick Brown moved to approve and Mr. Josh Martin seconded the motion. The Members Committee was in unanimous favor. The motion passed. MOPC Reorganization: A task force was assigned the task of reorganizing the SPP working groups for better communication and efficiency. The task force recommendation as recommended by MOPC is to approve: o o Moving the responsibilities of the Operations Model Development WG, Operations Data WG, and Operations Training WG to the Operating Reliability WG Moving the responsibilities of the Model Development WG to the Transmission WG Mr. Nick Brown moved to approve the MOPC reorganization and Mr. Julian Brix seconded the motion. The Member Committee was in unanimous favor. The motion passed. The working group scopes will by available to the Board of Directors for approval at the October meeting. The Corporate Governance Committee will review any necessary membership representation changes to ensure equal representation. OG&E, Woodward-Northwest 345kV Project for Board Approval: OG&E requested that SPP evaluate a proposed Woodward-Northwest 345 kv project to determine any impact on SPP system reliability and the SPP Transmission Expansion Plan (STEP) projects. In June 2008, SPP performed a load flow analysis on the project. In June 2008 the Transmission Working Group (TWG), finding no reliability issues, approved endorsement of the inclusion of the project in the STEP as a sponsored upgrade. The results showed that no 9 9 of 90

122 10 of 90 SPP Board of Directors/Members Committee Minutes July 29, 2008 existing facilities or approved STEP projects were impacted in a negative manner by the addition of the line and transformer, and no projects were deferred or advanced by the addition. Having the TWG recommendation in hand, the MOPC recommended that the Board of Directors approve the inclusion of OG&E s Woodward-Northwest 345kV project in the approved 2007 STEP as a sponsored project. Mr. Harry Skilton moved to approve and Mr. Larry Altenbaumer seconded the motion. Mr. Mel Perkins (OG&E) outlined the project and stressed the importance to the economy and development of northwest Oklahoma. He stated that OG&E hoped to build this project with a completion in early Mr. Carl Huslig (ITC Great Plains) stated that there are three areas he would like the Board to consider: 1) the motion should use the word endorse instead of approve for consistency; 2) ITC Great Plains requested to build with a Moreland hub and feels the Staff should perform an optimization study for the most appropriate hub; and 3) ITC Great Plains feels the issue should be tabled until October to wait on policy direction regarding the Right of First Refusal in the Tariff as directed by FERC s July 11, 2008 Order on Compliance in Docket No. OA It was noted that SPP cannot deny a sponsored project if no harm is determined. Following considerable discussion, Mr. Skilton and Mr. Altenbaumer amended the motion to read endorsed rather than approved. The Members Committee was in favor with Mr. David Brian (NTEC) opposed and Mr. Mitch Williams (WFEC) abstaining. The motion passed. Mr. Olsen then provided MOPC information items: Business Processes for Notification to Construct (NTC) and related planning processes; Cost Benefit Task Force activities; Consolidated Balancing Authority activities and future steps; and wind integration and accreditation efforts. Agenda Item 11 Human Resources Committee Report Ms. Phyllis Bernard provided the Human Resources Committee (HRC) Report (HRC Report Attachment 9). The group held a retreat on July 21 and 22 in Little Rock. Agenda and actions items were: Reviewed and approved the SPP Retirement Plan HRC advises the SPP Board of Directors to move ahead with execution of the Defined-benefit SERP plan for selected employees Reviewed potential change to the SPP Medical plan considering a partially self-funded plan Reviewed the SPP Benefit Plan considering potential enhancements Reviewed the 2009 Merit Pool and will meet in August to examine the percentage of increase proposed Established the 2009 HRC meeting schedule and agendas Agenda Item 12 Finance Committee Report Mr. Harry Skilton provided the Finance Committee report (Finance Report & Presentation Attachment 10). Action items included: 2008 Contract Services Budget With additional work required due to FERC Orders 890 and 693, Mr. Skilton moved that the Board of Directors approve increased staffing resources to 13 direct staff; increased expenses totaling $1,997,000; increased revenue totaling $3,235,000; and continued work to reduce liability exposure. Mr. Josh Martin seconded the motion. The Members Committee was in unanimous favor. The motion passed. Aircraft Lease To facilitate Staff travel, SPP plans to lease a 6-seat Piper Mirage Airplane from Arkansas Electric Cooperative Company (AECC) with SPP expecting to be responsible for 70% of the aircraft s fixed operating costs and AECC responsible for 30% (percentages represent expected use of the of 90

123 11 of 90 SPP Board of Directors/Members Committee Minutes July 29, 2008 aircraft). Mr. Skilton moved that the Board: Approve a seven year lease on an aircraft with several requirements pending review of final agreements: a. Lease should contain option to adjust rate based on actual use over a relevant period of time, b. Lease must comply with Federal Aviation Regulations and tax and financial reporting requirements to record lease as an operating lease on SPP s books, c. Finance Committee maintains final approval of lease and insurance terms, d. SPP staff to discuss lease of aircraft with regulators, e. SPP staff to develop comprehensive policy governing the use of the lease aircraft. Mr. Josh Martin seconded the motion. The Members Committee was in unanimous favor. The motion passed. The Finance Committee will monitor use of the aircraft providing ongoing utilization reports. Mr. Skilton noted that BKD will perform the financial audit and PricewaterhouseCoopers will perform the SASS 70 audit. Phase I of the Type II SASS 70 audit showed no deficiencies. Mr. Skilton commended Ms. Dianne Branch on a fine job. Mr. Tom Fritsche has developed an inventory of enterprise-wide risks to be more effective in risk management. Agenda Item 13 Strategic Planning Committee Report Mr. Richard Spring provided the Strategic Planning Committee (SPC) report. Mr. Spring provided the status of the Strategic Plan. Since January 2008 the committee has been working toward updating the current plan. A strawman was circulated in April with feedback considered at the May retreat. A draft has been distributed to the SPC for concurrence and will be sent to a broad stakeholder base for feedback this fall. The Revised Strategic Plan will be submitted for approval to the Board at the October meeting. A broad outline of the plan is: All are considered Priority A. Preamble outlook for SPP o Regulatory & Legislative Drivers o Human Resources o Mandatory Reliability Standards o Expansion of services and cost containment o Transmission Expansion o SPP Markets Communication and Education Membership Development/Expansion Transmission Expansion Market Development and Design Regional Reliability of 90

124 12 of 90 SPP Board of Directors/Members Committee Minutes July 29, 2008 Mr. Spring provided an update on the Transmission Ownership/Construction Task Force (TOCTF). The July 11, 2008 FERC Order on Compliance requires SPP to submit a further compliance filing within 90 days. One issue is the Right of First Refusal (ROFR) clarification for third party transmission owners. Three other specific areas will require further effort: 1) Demand response comparable treatment; 2) provisions related to five specific areas of local planning; and 3) inter-regional coordination agreements. The TOCTF will develop a policy recommendation on the ROFR to be reviewed by MOPC before requesting that RTWG develop Tariff language. Tariff changes would proceed through the normal path of MOPC and Board review and approval. Future Meetings Special Meeting of Members and Board of Directors/Members Committee teleconferences are tentatively scheduled for September 8 in order to approve requirements to integrate the Nebraska entities into SPP. The SPP Board of Directors /Members Committee Meeting and Annual Meeting of Members are in Tulsa, Oklahoma on October 28. The January 27, 2009 meeting location has not been determined (2008 BOD Meetings Attachment 11). Adjournment With no further business, Mr. Eckelberger thanked everyone for participating and adjourned the meeting at 2:30 p.m. with a brief recess before reconvening in Executive Session. Stacy Duckett, Corporate Secretary Executive Session The Board of Directors/Members Committee provided additional guidance to Staff regarding Contract Services activities of 90

125 13 of 90 Southwest Power Pool SPECIAL BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING Teleconference September 8, SUMMARY OF ACTION ITEMS- 1. Approved SPP Membership Agreement amendments to accommodate provisions of the Nebraska Public Power District (NPPD) and Omaha Public Power District (OPPD) as state power agencies and for Lincoln Energy System (LES) as a municipal utility to join SPP. 2. Approved SPP Tariff modifications to enable SPP membership of the Nebraska Public Power District, Omaha Public Power District and Lincoln Energy System. 13 of 90

126 14 of 90 MINUTES NO. 119 Southwest Power Pool SPECIAL BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING Teleconference September 8, 2008 Agenda Item 1 Administrative Items Chair Mr. Jim Eckelberger called the meeting to order at 10:17 a.m. The following Board of Directors/Member Committee members were in attendance via teleconference or represented by proxy: Mr. Larry Altenbaumer, director Ms. Phyllis Bernard, director Mr. Julian Brix, director Mr. Nick Brown, director Mr. Jim Eckelberger, director Ms. Trudy Harper, Tenaska Power Services Company Mr. Tom Stuchlik, for Mr. Kelly Harrison, Westar Energy Mr. Rob Janssen, Redbud Energy Mr. Jeff Knottek, City Utilities of Springfield Mr. Joshua Martin, director Mr. Steve Parr, Kansas Electric Power Cooperative, Inc. Mr. Phil Crissup, for 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. Rick Wolfinger, Constellation Power Source There were 43 persons in attendance via phone representing 12 members (Attendance List Attachment 1). Mr. Brown reported proxies and a quorum was declared (Proxies Attachment 2). Agenda Item 2 SPP Membership Agreement Amendments Ms. Stacy Duckett provided a review of proposed amendments to the SPP Membership Agreement to accommodate provisions for Nebraska Public Power District (NPPD) and Omaha Public Power District (OPPD) as state power agencies and for Lincoln Energy System (LES) as a municipal utility to join SPP (Membership Agreement Amendments Attachment 3). During a review of the proposed amendments at a Technical Conference held on August 26, it was suggested that some of these amendments should be incorporated into the SPP Membership Agreement for the benefit of all Members. The Corporate Governance Committee will review the amendments for the SPP Membership at large. Mr. Eckelberger asked for discussion or to entertain a motion. Mr. Harry Skilton moved to approve the recommended SPP Membership Agreement amendments. Mr. Julian Brix seconded the motion. The Members Committee was in unanimous favor. The motion passed. Agenda Item 3 Markets and Operations Policy committee Report/SPP Tariff Revisions Mr. John Olsen provided the first of two sets of Tariff revisions to allow the Nebraska Entities to begin operation in SPP (Tariff Revisions Attachment 4). The second set of Tariff revisions are expected to be submitted for review and approval at the regularly scheduled October 2008 meetings of the Markets and Operations Policy Committee and the Board of Directors/Members Committee. Mr. Altenbaumer moved to approve language for the proposed Tariff revisions and Mr. Josh Martin seconded the motion. The Members Committee was in unanimous favor. The motion passed. 14 of 90

127 15 of 90 SPP Board of Directors/Members Committee Minutes September 8, 2008 Adjournment With no further business, Mr. Eckelberger thanked everyone for participating and adjourned the meeting at 10:35 a.m. Stacy Duckett, Corporate Secretary 15 of 90

128 16 of 90 Southwest Power Pool, Inc. SOUTHWEST POWER POOL STAFF Recommendation to the Board of Directors October 28, 2008 Credit Policy Change Guaranty Agreement Representations and Warranties Organizational Roster The following individuals represented the Southwest Power Pool Credit Task Force at their meeting on October 9, 2007: Organization NRG Tenaska OG&E OG&E Aquila TEA Sunflower Representative Nithya Venkatesan Chair Mark Soulliere Vice Chair Debbie Fleming Carol Shoemake Jason Hill Terri Smith Justin Drake (Aces Power) The following SPP staff members participated in the meeting: Tom Fritsche, Director of Risk Management Phil McCraw, Senior Credit Risk Specialist Analysis Article Six of the SPP Credit Policy (Attachment X to the SPP Open Access Tariff) deals with Guarantees. A guaranty might be used by a customer in the event that the customer does not qualify for unsecured credit from SPP. Section of the Credit Policy requires a legal opinion from the guarantor stating that the guaranty is duly authorized. This section also requires the presentation of a resolution from the guarantor s board of directors or other governing body authorizing the execution of the guaranty agreement Appendix D to the SPP Credit Policy contains the form of the Guaranty Agreement used by SPP. Discussion The requirement for a legal opinion has long been a point of concern with new customers, particularly given that a board resolution approving the guaranty agreement is also required. The process of obtaining the opinion can also be protracted and this can delay the commencement of service by the customer. The main value of the legal opinion for SPP is to prevent the possibility of fraudulent conveyance and to confirm the adequacy of consideration for the guaranty. However, since most guaranties received by SPP are received from the parent company of subsidiary entities, these two issues are rarely a concern. The Task Force discussed these issues and concluded that the requirement for a legal opinion was no longer necessary. However, a board of directors resolution and the remaining language in Section must remain as a requirement. 16 of 90

129 17 of 90 The following solution was proposed: 1. Delete Section of the Credit Policy (see Exhibit I) 2. Amend Section 14 of the Guaranty Agreement to contain the following requirements (see Exhibit II): This representation is evidenced by a copy of the resolution(s) of the board of directors or other governing body of the Guarantor authorizing this Guaranty, which is attached to and made a part of this Agreement. This Guaranty is not in violation of other undertakings or requirements applicable to Guarantor, and is enforceable against the Guarantor in accordance with these terms; Conclusion The Credit Task Force motion to accept this proposal was made by Jason Hill and seconded by Mark Soulliere. The proposal was approved by a count of (i) Yes 7 (ii) No 0 Recommendation Approve the proposal as submitted. Approved: Credit Task Force October 9, 2007 Markets and Operations Policy Committee endorsed unanimously: October 14-15, 2008 The MOPC supports the RTWG recommended tariff language changes to Schedule 2 as requested by the Finance Committee. Finance Committee September 19, 2008 Action Requested: Approve Recommendation 17 of 90

130 18 of 90 Southwest Power Pool, Inc. MARKETS AND OPERATIONS POLICY COMMITTEE Recommendation to the Board of Directors October 28, 2008 Organizational Roster The following members represent the Operational Reliability Working Group: Kelson Energy American Electric Power CLECO Southwestern Public Service Westar Energy Arkansas Electric Cooperative Constellation Energy Kansas City Power & Light Sunflower Electric Power Empire District Electric City of Independence Oklahoma Gas & Electric Mr. Jason Atwood Mr. Scott Lockwood Mr. Danny McDaniel Mr. Kyle McMenamin Mr. Allen Klassen Mr. Keith Sugg Mr. Jim Thompson Mr. Jim Useldinger Mr. Noman Williams Mr. Brian Berkstresser Mr. Paul Lampe Mr. Donald Hargrove The following stakeholders participated in group discussions: Kelson Energy American Electric Power CLECO Southwestern Public Service Westar Energy Kansas City Power & Light Southwestern Public Service Empire District Electric City of Independence Oklahoma Gas & Electric Mr. Jason Atwood Mr. Scott Lockwood Mr. Danny McDaniel Mr. Kyle McMenamin Mr. Allen Klassen Mr. Jim Useldinger Mr. Kyle McMenamin Mr. Brian Berkstresser Mr. Paul Lampe Mr. Donald Hargrove Background SPP Criteria states that members are required to submit and the RC must grant approval for scheduled outages of critical facilities. Criteria also states that the ORWG will define what constitutes a critical facility. In the interests of avoiding a perceived conflict with the CIP standards, it was desired by members to remove reference to critical facilities and replace this language with a more specific list of those transmission facilities that the RC would need to grant approval for scheduled outages. Also in Criteria 5.2.1, language was added to provide documentation of the need for members to supply the RC with information on gas supply constraints pursuant to NAESB standard WEQ of 90

131 19 of 90 Analysis In the changes proposed the specific kv levels and types of facilities that the Reliability Coordinator would be required to study and provide approval for scheduled outages is identified. The requirements for submitting information concerning forced outages of these specific kv and types of facilities to the RC also are listed. Also added is the requirement of members to submit Operational Flow Orders (OFO s) and Critical Notices from their gas suppliers to the RC. In an vote, concluded on September 29, 2008, the ORWG approved this criteria addition with a vote of 10 in favor, none opposed, and no abstentions. Recommendation The MOPC recommends that the Board of Directors approve the changes to Criteria 5 it proposes. Approved: Operational Reliability Working Group September 29, 2008 Unanimously Approved Markets and Operations Policy Committee October 14-15, 2008 Unanimously Approved Action Requested: Approval of the proposed changes to the Criteria. Attachments: A redlined copy and a separate clean copy of the recommended changes to Criteria language is attached. 19 of 90

132 20 of 90 Southwest Power Pool Member Responsibilities Transmission Operators shall determine System Operating Limits (SOLs), as defined by NERCin Criteria14.2.4, in conjunction with transmission owners. SOLs will be provided for facilities that comprise flowgates and any other facilities as determined by the Transmission Operator in conjunction with the transmission owners. The Transmission Operator shall inform the Reliability Coordinator of changes to any SOL as specified in Appendix 7 and notify the Reliability Coordinator of any SOL violations. Control AreasBalancing Authorities and Transmission Operators shall notify the Reliability Coordinator of current or foreseen operating conditions that may adversely affect interconnection reliability. Transmission Operators shall submit sscheduled outages of critical transmission facilities shall be approved by the Reliability Coordinator. Scheduled outages of all transmission other facilities greater than kV to shall be submitted to and coordinated with the Reliability Coordinator. Scheduled outages of transmission facilities between 60kV and 100kV should be submitted for those facilities, that are identified by the RC and are included in the regional models., should be submitted. Scheduled outages of the following types of transmission facilities mustshall be approved by the Reliability Coordinator prior to implementing the outage: a. All transmission facilities rated at 230kV or above for transformers, use the low-side voltage class. b. All tie lines, 60kV and above. c. Allny other facilities, monitored and contingent elements, associated with flowgatesthat affect the capability and reliability of generating facilities (backup station power, etc.) d. Other facilities specified by the Transmission Operator or the Reliability Coordinator as having a major impact on the transmission system or that affect the capability and reliability of generating facilities (backup station power, etc).. Forced outages of all transmission facilities identified above greater than 60kV shall be submitted to the Reliability Coordinator along with estimated return-to-service time of the facility no later than 30 minutes after the outage. Forced outages of all other transmission facilities greater than kv and those identified facilities between 60kV and 100kV should be submitted as soon as practical after the outage. Any known updates to the return time should be submitted promptly to the Reliability Coordinator. The Operating Reliability Working Group shall be responsible for identifying those facilities classified as critical. Non-control areas shall notify their Control AreaBalancing Authority of current or foreseen operating conditions that may adversely affect interconnection reliability. Scheduled transmission outages shall be coordinated with their Control AreaBalancing Authority. Host Balancing AuthoritiesAs or Generator[r1]Transmission Operators, as appropriate, shall notify SPP of any generation derates resulting from Operational Flow Orders (OFOs) or Critical Notices [r2]or any other type of fuel delivery constraint. The parties submitting the information shall indicate that the derate is a result of an OFO, Critical Notices, or fuel delivery constraint and indicate which pipeline(s) or delivery constraints are impacting them. Whenever an OFO, Critical Notices, or fuel delivery constraint causes an inability for the ggenerator[r3] Ooperator to meet its firm obligations, it must use the normal established communication protocols to notify its host Balancing Authority. 6-1 July 24September 25, of 90

133 21 of 90 Southwest Power Pool Furthermore, host Balancing Authorities shall notify the SPP Rreliability Ccoordinator should it be necessary to request an NERC Energy Emergency Alert and/or an SPP Other Extreme Conditions as a result of the OFO or Critical Notice Operatiing Reliability Working Group The Operatiing Reliability Working Group shall be responsible for policy oversight of implementation and on-going reliability coordination processes and services as described in this Criteria. This working group shall make regular reports to the Engineering & OperatingMarkets and Operations Policy Committee. 6-2 July 24September 25, of 90

134 22 of 90 Southwest Power Pool, Inc. MARKETS AND OPERATIONS POLICY COMMITTEE Recommendation to the Board of Directors October 28, 2008 Attachment AP Recovery of Reliability Penalty Costs Organizational Roster The following persons are members of the Regional Tariff Working Group: Dennis Reed, WR (Chair) David Brian, ETEC (Vice-Chair) Bill Dowling, Midwest Energy David Kays, OGE Robert Pennybaker, AEP Bary Warren, EDE Mitch Williams, WFEC Ron Gary, LAFA Mike Proctor, MoPSC Bernie Liu, Xcel Rob Janssen, Redbud Gene Anderson, OMPA Mark Foreman, Tenaska Mike Wise, Golden Spread Charles Locke, KCPL Steve Ferry, Sunflower Robert Shields, AECC Rob Bowser, KEPCo Angela Easton, Calpine Pat Bourne, SPP Gerrud Wallaert, SPP (Secretary) Background During its September 25, 2008 meeting, the RTWG discussed and approved a revised version of proposed Attachment AP Allocation of Costs Associated with Reliability Penalty Assessments. The RTWG had previously approved an earlier version of Attachment AP at its August 28, 2008 meeting, but decided to revisit the language in order to address concerns raised by some RTWG members. The revised proposal provides greater specificity regarding the process governing SPP s potential allocation of monetary reliability penalty costs to Market Participants and Members. Attachment AP is designed to provide notice to Market Participants and Members that SPP may recover the costs of any penalties it incurs as a Registered Entity in the North American Electric Reliability Corporation ( NERC ) Compliance Registry, including both violations by SPP Market Participants and Members whose conduct causes SPP to incur a monetary penalty due to SPP s status as a Registered Entity and for SPP s own violations of NERC reliability standards. On March 20, 2008, the Federal Energy Regulatory Commission ( Commission ) issued an Order Providing Guidance on Recovery of Reliability Penalty Costs by Regional Transmission Organizations and Independent System Operators, recommending that RTOs include provisions in their tariffs and/or contracts with members and customers regarding responsibility for reliability-related monetary penalties and appropriate procedures for allocating such penalties. Analysis The primary purpose of Attachment AP is to provide notice to all SPP Market Participants and Members that they may be allocated the costs associated with monetary reliability penalties assessed against SPP either for their own conduct that contributed to a reliability violation or for penalties for which SPP is otherwise unable to assign penalty costs directly. Attachment AP also specifies the process SPP will undertake to allocate penalty costs either directly or through spreading of the costs to all Market Participants and Members. 22 of 90

135 23 of 90 In its March 20 Guidance Order, the Commission indicated that RTOs wishing to recover reliability penalty costs from their members or customers must provide notice to members and customers regarding potential reliability penalty cost recovery and recommended that RTOs include notice provisions in their tariffs and/or contracts. Additionally, the Commission declined to grant RTOs blanket authority to pass monetary penalties through to their members and customers automatically, instead requiring that RTOs file requests under section 205 of the Federal Power Act to assign reliability penalty costs on a case-bycase basis. The March 20 Guidance Order addressed both situations where certain Market Participants or Members are directly responsible for a reliability violation and thus can be directly assigned penalty costs by the RTO, and where the RTO itself is responsible or the responsible party cannot be directly assigned penalty costs. Section 1 of Attachment AP provides definitions applicable to Attachment AP. Section 2 of Attachment AP outlines the process SPP will undertake to assign reliability penalty costs directly to Market Participants or Members. Where SPP is informed of an investigation into a possible violation of a reliability standard, if SPP seeks to allocate any resulting reliability penalties to Market Participants and Members who are responsible for a portion or all responsibility for the violation, SPP will provide notice to such Market Participants or Members, as well as to the entity conducting the investigation (i.e. NERC, the Regional Entity, or the Commission), of its intent to assign any resulting penalty costs. The Market Participants or Members will be provided the opportunity to fully participate in the proceedings. If a violation is found and SPP is assessed a monetary penalty for the violation, SPP will file a request under section 205 of the Federal Power Act to assign the penalty costs directly to the Market Participants and Members identified by the investigation to whom SPP had previously provided notice. Section 3 of Attachment AP describes the process SPP will follow in the event that it is assessed a monetary reliability penalty for either its own violation of a reliability standard or for conduct by a party who cannot otherwise be directly assigned penalty costs. SPP will notify any potentially affected Market Participants or Members of an alleged or confirmed violation and invite the Market Participants or Members to participate in the proceedings. SPP will timely report status and results to the Members. Section 3 requires SPP to make a filing under section 205 of the Federal Power Act to spread reliability penalty costs among all Market Participants and Members. Attachment AP is drafted in accordance with the guidance provided in the Commission s March 20 Guidance Order and adopts procedures similar to those recently approved by the Commission for PJM. No minority opinion was expressed to the adoption of Attachment AP. Recommendation The recommendation of the Markets and Operations Policy Committee to the Board of Directors is to approve the tariff language for the newly created Attachment AP. Approved: Regional Tariff Working Group September 25, 2008 Unanimously Approved Markets and Operations Policy Committee October 14-15, 2008 Unanimously Approved Action Requested: Approve Recommendation 23 of 90

136 24 of 90 ATTACHMENT AP Allocation of Costs Associated with Reliability Penalty Assessments Under the NERC Functional Model and NERC Rules of Procedure, the Transmission Provider may be assessed penalties for confirmed violations of the NERC Reliability Standards. The purpose of this Attachment is to provide notice to all Market Participants and Members that they may potentially be responsible for penalty costs assessed against the Transmission Provider for confirmed violations of any NERC Reliability Standard. Market Participants and Members may be either directly assigned such penalty costs, if it is determined that they are responsible for or have directly contributed to the confirmed violations at issue, or may be assigned a portion of the costs, if the Transmission Provider is assessed a monetary penalty either due to its own confirmed violation or its status, as a Registered Entity under the NERC Functional Model and NERC Rules of Procedure. This Attachment also provides for the recovery of costs associated with penalties assessed against the Transmission Provider for confirmed violations of NERC Reliability Standards resulting from a confirmed violation of NERC Reliability Standards by a Market Participant(s), Member(s), the Transmission Provider, or another entity for whom Transmission Provider is assessed a penalty due to its status as a Registered Entity under the NERC Functional Model and NERC Rules of Procedure. Under this Attachment, the Transmission Provider may seek recovery of the costs associated with any monetary penalty by filing under section 205 of the Federal Power Act for direct recovery of penalty costs from one or more Market Participants or Members and/or for an allocation of penalty costs among all Market Participants and Members. Additionally, this Attachment provides for the participation of Market Participants in the penalty assessment process with the Transmission Provider if the Market Participant is alleged to have been directly involved in the event causing the potential penalty. 1. Definitions All defined terms in this Attachment shall have the meaning given to them in the Tariff unless otherwise stated below. Compliance Monitoring and Enforcement Program The program used by NERC and the Regional Entities to monitor, assess, and enforce compliance with Reliability Standards within the United States. This is accomplished through compliance monitoring and audits, as well as the conduct of investigations and the assessment of monetary and non-monetary penalties for violations. Electric Reliability Organization or ERO An organization certified by the Commission to develop and enforce mandatory reliability standards and assess penalties against users, owners and operators of the bulk power system that violate such standards. North American Electric Reliability Corporation ( NERC ) The organization designated as ERO by the Commission on July 20, NERC Compliance Registry The registry maintained by NERC that records which Registered Entity is responsible for performing the set of functions required to ensure compliance with each NERC Reliability Standard. NERC Functional Model The Model defining the set of functions that must be performed to ensure the reliability of the electric bulk power system. The NERC Reliability Standards establish the requirements of the responsible entities that perform the functions defined in the Functional Model. 24 of 90

137 25 of 90 NERC Reliability Standards Standards developed by NERC and approved by the Commission to ensure reliability of the bulk power system, violation of which may result in the imposition of mitigation programs or monetary penalties. NERC Rules of Procedure The rules and procedures developed by NERC and approved by the Commission. These rules include the process by which a responsible entity, who is to perform a set of functions to ensure the reliability of the electric bulk power system, must register as a Registered Entity. Registered Entity The entity registered under the NERC Functional Model and NERC Rules of Procedures for the purpose of compliance with NERC Reliability Standards and responsible for carrying out the tasks within a NERC function without regard to whether a task(s) is performed by another entity pursuant to the terms of its governing documents. Regional Entity (RE) NERC has designated the Transmission Provider as Regional Entity in the SPP region and has delegated ERO functions to Transmission Provider in the region. 2. Direct Assignment of Costs Where Violation Can Be Directly Assigned The purpose of this section of this Attachment is to provide notice to all Market Participants and Members that they may potentially be responsible for reliability penalty costs assessed in the event that the Market Participant s or Member s conduct or omission contributed to the violation(s) for which a monetary penalty was assessed to the Transmission Provider. This section provides for notification for the potential direct assignment of costs related to reliability violations that may be assessed to the Transmission Provider. The Transmission Provider shall notify, in writing, any potentially affected Member(s) or Market Participant(s) of an alleged violation as soon as possible after notifications by the RE or NERC of the commencement of procedures under the Compliance Monitoring and Enforcement Program. In addition, the Transmission Provider will invite the affected Member(s) or Market Participant(s) to fully participate in all discussions and/or proceedings under the Compliance Monitoring and Enforcement Program. If there is i) an assessment of a monetary penalty against the Transmission Provider as the Registered Entity for a confirmed violation of a NERC Reliability Standard(s) and ii) as a result of proceedings under the Compliance Monitoring and Enforcement Program, it is determined that one or more Market Participants, Members or Registered Entities are deemed to have directly contributed to or found to have been a root cause(s) of such confirmed violation(s), such Market Participant(s) or Member(s) may be assessed a portion of or all of the monetary penalty; provided that all of the following conditions have been satisfied: (1) During the course of an investigation by NERC, the RE or the Commission regarding the possibility of a Transmission Provider alleged violation of a NERC Reliability Standard, if the Transmission Provider believes that a Market Participant(s) or Member(s) may have contributed to the violation under investigation, the Transmission Provider will provide a) reasonable prior written notice to the Market Participant(s) or Member(s) that the Transmission Provider believes may have contributed to the violation and that it intends to seek to hold the Market Participant(s) or Member(s) responsible for a portion of or all of the monetary penalties that result; and b) the Market Participant(s) or Member(s) is provided the opportunity to fully participate in all discussions and/or proceedings under the Compliance Monitoring and Enforcement Program. (2) In addition to the Transmission Provider providing sufficient notice to a Market Participant(s) or Member(s) under Section 2(1) of this Attachment, it will also provide notice to NERC, the RE and the Commission of its allegations that the Market Participant(s) or Member(s) may have contributed to the alleged violation and that the Transmission Provider intends to hold the Market Participant(s) or Member(s) responsible 25 of 90

138 26 of 90 for a portion of or all of the monetary penalties that result from the investigation which determines to what extent the Market Participant(s) or Member(s) contributed to or was a root cause(s) of the confirmed violation; (3) If, as a result of proceedings under the Compliance Monitoring and Enforcement Program, it is determined that the Market Participant(s) or Member(s) cited by the Transmission Provider contributed to or was a root cause(s) of the alleged violation, the Transmission Provider will seek to hold the Market Participant(s) or Member(s) responsible for a portion of or all of the monetary penalty assessed as a result of the confirmed violation by making a filing with the Commission under section 205 of the Federal Power Act to assign a portion of or all of the costs of the monetary penalty directly to the Market Participant(s) or Member(s); (4) If the Commission accepts the filing, the Market Participant(s) or Member(s) shall be responsible for its portion of the monetary penalty as determined by the Commission s order on the section 205 filing. 3. Spreading of Costs Where Violation Cannot Be Directly Assigned The purpose of this section of this Attachment is to provide notice to all Market Participants and Members that they may potentially be responsible for reliability penalty costs assessed to the Transmission Provider that cannot be directly assigned under Section 2 of this Attachment.. This section provides for a spreading of a portion of or all of such reliability penalty costs among all Market Participants and Members where the Transmission Provider itself is responsible for a confirmed violation of a Reliability Standard or where the Transmission Provider is assessed a penalty because of its status as a Registered Entity for a given Reliability Standard and the entity responsible for the violation cannot be assessed a penalty because of its status. The Transmission Provider shall notify, in writing, any potentially affected Market Participant(s) or Member(s) of an alleged or confirmed violation as soon as possible after notifications by the RE or NERC of the commencement of procedures under the Compliance Monitoring and Enforcement Program. In addition, the Transmission Provider will i) invite the affected Member(s) or Market Participant(s) to fully participate in all discussions and/or proceedings under the Compliance Monitoring and Enforcement Program and ii) timely report status and results of the findings and remedies to the Members. If there is an assessment of a monetary penalty against the Transmission Provider as the Registered Entity for a confirmed violation of a NERC Reliability Standard(s), either: (1) as a result of the Transmission Provider s own conduct or omission that resulted in a confirmed violation; or (2) as a result of a violation by another entity for whom the Transmission Provider is the Registered Entity where the entity is not on the NERC Compliance Registry and therefore cannot be directly assessed a penalty because of its status; Market Participants and Members may be assessed a portion of the monetary penalty providing the following conditions have been satisfied: (1) The Transmission Provider has made a filing under section 205 of the Federal Power Act proposing a methodology to allocate a portion of or all of the costs of the monetary penalty among the Market Participants and Members; (2) If the Commission accepts the filing and finalizes such penalty allocations to the Market Participants and Members. 26 of 90

139 27 of 90 Southwest Power Pool, Inc. MARKETS AND OPERATIONS POLICY COMMITTEE Recommendation to the Board of Directors October 28, 2008 Project Sponsor Upgrade Agreement Organizational Roster The following persons are members of the Region Tariff Working Group: Dennis Reed, WR (Chair) David Brian, ETEC (Vice-Chair) Bill Dowling, Midwest Energy David Kays, OGE Robert Pennybaker, AEP Bary Warren, EDE Mitch Williams, WFEC Ron Gary, LAFA Mike Proctor, MoPSC Bernie Liu, Xcel Rob Janssen, Redbud Gene Anderson, OMPA Mark Foreman, Tenaska Mike Wise, Golden Spread Charles Locke, KCPL Steve Ferry, Sunflower Robert Shields, AECC Rob Bowser, KEPCo Angela Easton, Calpin Pat Bourne, SPP Gerrud Wallaert, SPP (Secretary) Background The development of these proposed changes is an outgrowth of SPP s continuing efforts to refine its transmission planning and cost allocation processes. One type of Network Upgrade in the SPP transmission planning process is a Sponsored Upgrade. A Sponsored Upgrade is a Network Upgrade for which the Directly Assigned Upgrade Cost is borne voluntarily by a Project Sponsor. In late 2007, SPP Staff initiated an analysis of what process and agreements were necessary for a Project Sponsor to voluntarily bear the Direct Assignment Upgrade Cost of the Sponsored Upgrade. The primary focus of the analysis was the required contents of a pro forma agreement to be incorporated into SPP s OATT. SPP Staff submitted its initial proposal to the RTWG at its January meeting. The RTWG continued the review process at its regular monthly meetings, sometimes with intermittent conference calls of appointed subgroups. It completed its efforts at its September 26 meeting. Analysis The primary component of the proposal is an Agreement for Sponsored Upgrade ( Agreement ) to be attached as Schedule 1 to Attachment J of the OATT. The terms of the Agreement include the effective date, termination date, the introduction of a term known as a Project Sponsor s Payment, Letter of Credit requirements, recognition of revenue credit payments pursuant to Attachment Z2 of the OATT, a commitment for SPP to arrange for construction of the Sponsored Upgrade and notice requirements. Changes to Attachment J provide detail to the requirements referenced in the Agreement. The Project Sponsor s Payment may be in the form of a lump-sum payment or a periodic charge calculated in accordance with FERC policy. The present value of the Project Sponsor s Payment must be equal to the present value of the annual revenue requirements of the Sponsored Upgrade over a twenty year plant life, which shall include appropriate O&M expenses and 27 of 90

140 28 of 90 address tax consequences. The Direct Assigned Upgrade Cost will initially be provided to the Project Sponsor as an estimate but trued up after construction, at which time the final Project Sponsor s Payment will be calculated. During the course of the RTWG s deliberations, it raised an issue regarding the consequences of revenue credits exceeding the periodic Project Sponsor s Payment. The RTWG proposes in principle that such excess credits should be paid to the Transmission Owner building the Sponsored Upgrade, thereby reducing the amount of the Directly Assigned Upgrade Cost. These changes are not included in this proposal due to the RTWG s desire to implement these changes on an expedited basis. However, the RTWG anticipates submitting an additional proposal in the future to address this issue. Areas of the tariff where proposed changes occur: Attachment J, Recovery of Costs Associated with New Facilities, including a new Agreement for Sponsored Upgrade. Recommendation: The MOPC recommends that the Board of Directors approve the Tariff changes allowing the RTWG to make any non-substantive changes to the Tariff language necessary for filing at the Commission. Approved: Regional Tariff Working Group September 25 26, 2008 Unanimously Approved Markets and Operations Policy Committee October 14-15, 2008 Approved with 1 Abstention (ITC Great Plains); No Opposition Action Requested: Approve Recommendation 28 of 90

141 29 of 90 Page 1 of 4 Agreement For Sponsored Upgrade This Agreement For Sponsored Upgrade ("Agreement") is entered into this day of,, by and between ("Project Sponsor"), and Southwest Power Pool, Inc. ("Transmission Provider") on behalf of itself and the designated Transmission Owner(s). The Project Sponsor and Transmission Provider shall be referred to as "Parties." WHEREAS, the Transmission Provider administers an Open Access Transmission Tariff ( Tariff ) to provide Transmission Service within the Southwest Power Pool and acts as agent for the Transmission Owners in providing service under the Tariff; and WHEREAS, the Sponsored Upgrade identified in the Specifications attached hereto has been endorsed by the Markets and Operations Policy Committee and the Board of Directors of the Transmission Provider; and WHEREAS, the Project Sponsor has agreed to bear the cost of the Sponsored Upgrade; and WHEREAS, the Parties intend that capitalized terms used herein shall have the same meaning as in the Tariff; NOW, THEREFORE, in consideration of the mutual covenants and agreements herein, the Parties agree as follows: 1.0 This Agreement shall become effective on the later of (l) the date of the execution of this Agreement by both Parties or (2) such other date as it is permitted to become effective by the Commission. ( Effective Date ) 2.0 This Agreement shall terminate on the later of the following events: (1) the Project Sponsor has fulfilled its obligation to make Project Sponsor s Payment pursuant to section 3.0 or (2) the Transmission Provider has fulfilled its obligation to pay the Project Sponsor all revenue credits pursuant to section 5.0, recognizing that no obligation to pay revenue credits will remain after the Sponsored Upgrade has been permanently removed from service. 3.0 Project Sponsor agrees to pay the Directly Assigned Upgrade Costs of the Sponsored Upgrade pursuant to Attachment J of the Tariff. Project Sponsor has elected to pay for the Sponsored Upgrade in one of the following manners, as indicated in the Specifications attached hereto: (1) by a lump sum payment or (2) a periodic charge, both hereinafter referred to as Project Sponsor s Payment. The Parties recognize that the initial Project Sponsor s Payment will be based on an estimate of the Directly Assigned Upgrade Costs. While Transmission 29 of 90

142 30 of 90 Page 2 of 4 Provider represents that the Project Sponsor s Payment is based on a good faith estimate of the Directly Assigned Upgrade Costs, such estimate shall not be binding, and the Project Sponsor shall compensate the Transmission Provider and designated Transmission Owner(s) for all costs incurred pursuant to the provisions of the Tariff. Promptly after the Sponsored Upgrade is placed in service, Transmission Provider shall adjust the Project Sponsor s Payment to reflect all such costs incurred, as appropriate. 4.0 Project Sponsor shall maintain a Letter of Credit in the amount specified in this Agreement or such other form of security acceptable to Transmission Provider pursuant to Attachment X of the Tariff until such time as the Project Sponsor has fulfilled its obligation to make Project Sponsor s Payment pursuant to section Transmission Provider agrees to provide Project Sponsor with revenue credits pursuant to Attachment Z2 of the Tariff. Revenue credits shall be the exclusive compensation of the Project Sponsor under this Agreement. 6.0 Transmission Provider agrees to arrange for the construction of the Sponsored Upgrade in accordance with the Tariff, the SPP Membership Agreement and the construction timeline specified herein. 7.0 Any notice or request made to or by either Party regarding this Agreement shall be made to the representative of the other Party as indicated below. Southwest Power Pool, Inc.: 415 N. McKinley, Suite 140 Little Rock, AR Project Sponsor: 30 of 90

143 31 of 90 Page 3 of The Tariff is incorporated herein and made a part hereof for all purposes. IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed by their respective authorized officials. Southwest Power Pool, Inc.: By: Name Title Date Project Sponsor: By: Name Title Date 31 of 90

144 32 of 90 Page 4 of 4 Specifications 1.0 Designated Transmission Owner(s): 2.0 Description of Sponsored Upgrade: 3.0 Project Sponsor s Payment:* The Project Sponsor shall elect to pay the Directly Assigned Upgrade Grade Costs of the Sponsored Upgrade by (1) a lump sum payment or (2) a periodic charge as indicated below: Lump Sum Payment: Periodic Charge: Payment Due Date: * The Project Sponsor s Payment specified herein shall initially be based on a good faith estimate of Directly Assigned Upgrade Costs. The Project Sponsor s Payment shall be subject to adjustment and true up after the Sponsored Upgrade is placed in service. 4.0 Project Timeline (Milestones): 5.0 Letter of Credit: 32 of 90

145 33 of 90 Southwest Power Pool First Revised Sheet No. 226 FERC Electric Tariff Superseding Original Sheet No. 226 Fifth Revised Volume No. 1 ATTACHMENT J DRAFT Recovery Of Costs Associated With New Facilities I. Direct Assignment Facilities Where a System Impact and/or Facilities Study indicates the need to construct II. III. Direct Assignment Facilities to accommodate a request for Transmission Service, the Transmission Customer shall be charged the full cost of such Direct Assignment Facilities. Such costs shall be specified in a Service Agreement. Network Upgrades Where applicable the costs of completed Network Upgrades shall be allocated as specified in Sections III, IV and V of this Attachment. The revenue requirements of Base Plan Upgrades and approved Balanced Portfolios will be recovered through Schedule 11, subject to filing such rate or revenue requirement changes with the Commission, and where applicable Directly Assigned Upgrade Costs. The revenue requirements for other Network Upgrades may be recovered by Transmission Owners through Schedules 7, 8, and 9 subject to their filing such rate or revenue requirement changes with the Commission. Base Plan Upgrades A single Base Plan Upgrade is comprised of any upgrade or group of upgrades required to be made to a single transmission circuit, where a transmission circuit is comprised of all elements load carrying between circuit breakers or the comparable switching devices. A. Allocation of Base Plan Upgrade Costs 1. If the cost of a Base Plan Upgrade is less than or equal to $100,000, the annual transmission revenue requirement associated with such Base Plan Upgrade shall be allocated to the Base Plan Zonal Annual Transmission Revenue Requirement of the Zone in which the Base Plan Upgrade is located. Issued by: L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: March 28, 2008 Effective: May 27, of 90

146 34 of 90 Southwest Power Pool First Revised Sheet No. 227 FERC Electric Tariff Superseding Original Sheet No. 227 Fifth Revised Volume No If the cost of a Base Plan Upgrade is greater than $100,000, then: i. X% of the annual transmission revenue requirement associated ii. with such Base Plan Upgrade shall be allocated to the Base Plan Region-wide Annual Transmission Revenue Requirement and recovered through the Region-wide Charge. The initial value of X shall be 33%. (100-X)% of the annual transmission revenue requirement associated with such Base Plan Upgrade shall be allocated to the Base Plan Zonal Annual Transmission Revenue Requirement and recovered through the Base Plan Zonal Charge. This portion of the annual transmission revenue requirement for each Base Plan Upgrade shall be allocated to the Base Plan Zonal Annual Transmission Revenue Requirement of specific Zones based on the Zones share of the incremental positive MW-mile benefits as computed in Section 4 of Attachment S to this Tariff. Each Zone with a benefit of at least 10 MW-miles from a given Base Plan Upgrade shall be allocated a portion of the Base Plan Zonal Annual Transmission Revenue Requirement for such upgrade based on its incremental positive MW-mile benefit divided by the sum of the incremental positive MW-mile benefits for all of those Zones with a benefit of at least 10 MW-miles from the upgrade, provided that such allocation represents an engineering and construction cost of at least $100,000. Issued by: L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: August 3, 2007 Effective: August 4, of 90

147 35 of 90 Southwest Power Pool First Revised Sheet No. 228 FERC Electric Tariff Superseding Original Sheet No. 228 Fifth Revised Volume No. 1 B. Conditions for Classifying Service Upgrades Associated with Designated Resources As Base Plan Upgrades If the cost of any Service Upgrade or group of Service Upgrades to a single transmission circuit associated with a new or changed Designated Resource is less than or equal to $100,000: (i) such upgrade(s) shall be classified as a Base Plan Upgrade; and (ii) the annual transmission revenue requirement associated with such upgrade(s) shall be allocated in accordance with Section III.A.1. Service Upgrades, with a cost that exceeds $100,000, associated with new or changed Designated Resources shall be classified as Base Plan Upgrades if all the following conditions apply: 1. The Transmission Customer s commitment to the Designated Resource has a duration of at least five years; 2. In the first year the Designated Resource is planned to be used by the Transmission Customer, the accredited capacity of the Transmission Customer s existing Designated Resources plus the lesser of: (a) the planned maximum net dependable capacity applicable to the Transmission Customer or (b) the requested capacity; shall not exceed 125% of the Transmission Customer s projected system peak responsibility determined pursuant to SPP Criteria 2; and 3. The cost of Service Upgrades associated with the new or changed Designated Resource is less than or equal to $180,000/MW times the lesser of: (a) the planned maximum net dependable capacity applicable to the Transmission Customer or (b) the requested capacity (the Safe Harbor Cost Limit ). Issued by: L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: March 28, 2008 Effective: May 27, of 90

148 36 of 90 Southwest Power Pool First Revised Sheet No. 229 FERC Electric Tariff Superseding Original Sheet No. 229 Fifth Revised Volume No. 1 The Transmission Customer must provide the Transmission Provider the information that the Transmission Provider deems necessary to verify that the new or changed Designated Resource meets conditions 1 and 2 above. If an upgrade for a new or changed Designated Resource meets the requirements set forth in 1 and 2 above, the costs up to the $180,000/MW Safe Harbor Cost Limit will be classified as Base Plan Upgrade costs. If the conditions set forth in 1 and 2 above are not met, and the Transmission Customer does not secure a waiver of the relevant condition(s), the costs of the upgrades will be directly assigned to the Transmission Customer. If the costs of upgrades associated with a new or changed Designated Resource exceeds the Safe Harbor Cost Limit and the Transmission Customer does not secure a waiver of that limit, the costs of the upgrades in excess of the limit will be directly assigned to the Transmission Customer. The Transmission Customer shall receive transmission revenue credits in accordance with Attachment Z2 to this Tariff for any such directly assigned costs. C. Waiver of Conditions for Classifying Service Upgrades Associated with Designated Resources As Base Plan Upgrades 1. Waiver Process If one or more of the conditions in Section III.B. are not met, the Transmission Customer may seek a waiver from the Transmission Provider in order that the costs of the Service Upgrade that otherwise would be directly assigned to the Transmission Customer may be classified in whole or in part as Base Plan Upgrade costs. Issued by: L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: March 28, 2008 Effective: May 27, of 90

149 37 of 90 Southwest Power Pool First Revised Sheet No. 230 FERC Electric Tariff Superseding Original Sheet No. 230 Fifth Revised Volume No. 1 If the conditions set forth in Section III.B.1. or III.B.2. of this Attachment are not met, the Transmission Customer must submit its request for a waiver to the Transmission Provider simultaneous with its request for long-term transmission service, submitted in accordance with Attachment Z1 to this Tariff, for the new or changed Designated Resource. Studies performed by the Transmission Provider as part of the Aggregate Transmission Service Study procedure, which is described in Attachment Z1, will determine whether the costs for Service Upgrades associated with a new or changed Designated Resource may exceed the Safe Harbor Cost Limit. If the Transmission Provider determines that the costs for Service Upgrades associated with a new or changed Designated Resource may exceed the Safe Harbor Cost Limit, the Transmission Provider shall notify the affected Transmission Customer when the Transmission Provider posts the associated Facilities Study. If the affected Transmission Customer intends to request a waiver regarding the costs in excess of the Safe Harbor Cost Limit, the Transmission Customer must submit to the Transmission Provider its request for a waiver within 15 days of such notice. Following receipt of a request for a waiver, the Transmission Provider will review the request and make a determination on a nondiscriminatory basis of whether a waiver should be granted based upon consideration of the factors described in Section III.C.2. of this Attachment. The Transmission Customer requesting the waiver shall be responsible for the reasonable costs of any studies that the Transmission Provider performs in Issued by: L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: March 28, 2008 Effective: May 27, of 90

150 38 of 90 Southwest Power Pool First Revised Sheet No. 231 FERC Electric Tariff Superseding Original Sheet No. 231 Fifth Revised Volume No. 1 making its determination. The Transmission Provider will provide a report and recommendation to the Markets and Operations Policy Committee for each requested waiver. The Markets and Operations Policy Committee will consider the waiver request and the Transmission Provider s report and recommendation, and will provide its own recommendation (along with the Transmission Provider s report and recommendation) regarding each requested waiver to the SPP Board of Directors. Barring unusual circumstances, a valid waiver request will be reviewed and submitted to the SPP Board of Directors within 120 days following the receipt of the waiver request. 2. Factors to be Considered in Evaluating Waiver Requests Any waiver request submitted by a Transmission Customer pursuant to Section III.C.1. of this Attachment shall be evaluated based upon the following general factors, including but not limited to: i. There are insufficient competitive resource alternatives for one or more Transmission Customers. ii. In the event that the aggregate costs of a Service Upgrade associated with a new or changed Designated Resource exceed the Safe Harbor Cost Limit, (i) those costs up to the level of the Safe Harbor Cost Limit shall be classified as Base Plan Upgrade costs, and (ii) those costs that exceed the Safe Harbor Cost Limit may be classified in whole or in part as Base Plan Upgrade costs taking into account the extent to which the duration of the Transmission Customer s commitment to the new or changed Designated Resource exceeds the five-year commitment period set forth in paragraph III.B.1. above. Issued by: L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: March 28, 2008 Effective: May 27, of 90

151 39 of 90 Southwest Power Pool First Revised Sheet No. 232 FERC Electric Tariff Superseding Original Sheet No. 232 Fifth Revised Volume No. 1 iii. The five-year commitment period for the new or changed Designated Resource may be waived if: (i) the associated Service Upgrade costs are significantly less than the Safe Harbor Cost Limit; or (ii) the associated Service Upgrades provide benefits to other Transmission Customers that would offset in less than five years any costs allocated to them as a result of the upgrade being classified as a Base Plan Upgrade. iv. If a request for a waiver is received by the Transmission Provider based upon other circumstances, such waiver request shall also be considered pursuant to the waiver process described in Section III.C.1. of this Attachment. If the costs of the Service Upgrade(s) required for a new or changed Designated Resource are not eligible for classification as Base Plan Upgrade costs, the Transmission Customer may nevertheless request the construction of such upgrades. In such event, the costs of such upgrades shall be allocated in accordance with Attachment Z1 to this Tariff. D. Review of Base Plan Allocation Methodology 1. The Transmission Provider shall review the reasonableness of the regional allocation factor (X%) and the zonal allocation methodology at least once every five years. The Transmission Provider and/or the Regional State Committee may initiate a review of the regional allocation factor and/or the zonal allocation methodology if either body determines that circumstances warrant. Any change in the regional allocation factor and/or the zonal allocation methodology shall be filed with the Commission. Issued by: L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: March 28, 2008 Effective: May 27, of 90

152 40 of 90 Southwest Power Pool First Revised Sheet No. 233 FERC Electric Tariff Superseding Original Sheet No. 233 Fifth Revised Volume No. 1 IV. 2. For each SPP Transmission Expansion Plan, the Transmission Provider shall calculate the cost allocation impacts of the Base Plan Upgrades to each Transmission Customer within the SPP Region. The results will be reviewed for unintended consequences by the Regional Tariff Working Group and reported to the Markets and Operations Policy Committee and Regional State Committee. Approved Balanced Portfolios One hundred percent (100%) of the annual transmission revenue requirement for an approved Balanced Portfolio shall be recovered through the Region-wide Charge. A. Reallocation of Zonal Revenue Requirements for Deficient Zone(s) For an approved Balanced Portfolio, the balance may have been achieved by transferring a portion of the Base Plan Zonal Annual Transmission Revenue Requirement and/or the Zonal Annual Transmission Revenue Requirement from the deficient Zone(s) to the Balanced Portfolio Region-wide Annual Transmission Revenue Requirement in accordance with Section IV.7.c of Attachment O to this Tariff. 1. Timing of Reallocation of Zonal Revenue Requirements for Deficient Zone(s) The initial reallocation of the zonal annual transmission revenue requirements from the deficient Zone(s) to the Balanced Portfolio Regionwide Annual Transmission Revenue Requirement shall occur when at least 10% of the estimated levelized annual transmission revenue requirements for the approved Balanced Portfolio has been included in rates under the Tariff (the Trigger Date ). On the Trigger Date and on the anniversary of the Trigger Date in each of the subsequent four years, 20% of the zonal annual transmission revenue requirements required to balance the portfolio for the deficient Zone(s), as estimated in accordance with Section IV.7.c of Attachment O to this Tariff, shall be reallocated to the Balanced Portfolio Region-wide Issued by: L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: March 28, 2008 Effective: May 27, of 90

153 41 of 90 Southwest Power Pool Original Sheet No FERC Electric Tariff Fifth Revised Volume No. 1 Annual Transmission Revenue Requirement. If all the upgrades in the approved Balanced Portfolio are completed and included in rates under the Tariff prior to the fourth anniversary of the Trigger Date, the final reallocation shall be performed and the true-up specified in Section IV.A.2 of this Attachment shall be performed at the time that all of the upgrades in the approved Balanced Portfolio are completed and included in rates under the Tariff. The reallocation of the zonal annual transmission revenue requirements shall be from the Base Plan Zonal Annual Transmission Revenue Requirement of the deficient Zone(s) first, then, if necessary, from the Zonal Annual Transmission Revenue Requirement of the deficient Zone(s). 2. Final Reallocation of Zonal Revenue Requirements for Deficient Zone(s) and True-up Upon the completion and inclusion in rates under the Tariff of all of the upgrades that are part of the approved Balanced Portfolio the final amount of costs to be reallocated from the zonal annual transmission revenue requirements for the deficient Zone(s) to the Balanced Portfolio Region-wide Annual Transmission Revenue Requirement to balance the approved Balanced Portfolio shall be trued-up based on the applicable fixed charge rate and actual cost for each upgrade. The final reallocation of costs shall be performed using the same benefits estimated at the time the Balanced Portfolio was approved. Notwithstanding the foregoing, if the ten-year net present value of levelized annual transmission revenue requirements based on actual costs exceeds the ten-year net present value of estimated benefits for the entire approved Balanced Portfolio, then the reallocation for each Zone shall be set at a level that equates the benefit to cost ratio in each Zone to the truedup benefit to cost ratio for the approved Balanced Portfolio. B. Reconfiguration of an Approved Balanced Portfolio 41 of 90

154 42 of 90 Southwest Power Pool Original Sheet No FERC Electric Tariff Fifth Revised Volume No Conditions Under Which an Approved Balanced Portfolio may be Reconfigured The Transmission Provider may review and recommend reconfiguring a previously approved Balanced Portfolio. Conditions that may initiate such review and recommendation, include but are not limited to: i. Cancellation of an upgrade that is part of an approved Balanced Portfolio; ii. Increases in the costs of upgrades that are part of an approved Balanced Portfolio; and iii. Significant unanticipated changes in the transmission system. The Transmission Provider shall determine the costs and benefits of a reconfigured Balanced Portfolio. 2. Factors to be Considered in Determining How a Balanced Portfolio Should be Reconfigured Reconfiguration of a Balanced Portfolio shall be evaluated based upon the following general factors, including but not limited to, the impact of the reconfiguration on: i. Meeting the conditions for a Balanced Portfolio specified in Section IV.6.e of Attachment O to this Tariff; ii. The number of deficient Zones as defined in Section IV.7.a of Attachment O to this Tariff; iii. The amount of zonal annual transmission revenue requirements that needs to be transferred from the deficient Zone(s) to the Balanced Portfolio Region-wide Annual Transmission Revenue Requirement in order to balance the reconfigured portfolio; and iv. The increase in the overall cost of the reconfigured Balanced Portfolio, if upgrades are added to the portfolio. 3. Reallocation of Zonal Revenue Requirements for Deficient Zone(s) If a reconfigured portfolio is to be balanced by transferring a portion of the zonal annual transmission revenue requirements from the 42 of 90

155 43 of 90 Southwest Power Pool Original Sheet No FERC Electric Tariff Fifth Revised Volume No. 1 deficient Zone(s) to the Balanced Portfolio Region-wide Annual Transmission Revenue Requirement, the reallocation of the revenue requirements specified in Section IV.A of this Attachment shall be adjusted based on the costs and benefits of the proposed reconfigured Balanced Portfolio as approved. 4. Recommendation and Approval of a Reconfigured Balanced Portfolio Based on the analysis performed in accordance with Sections IV.B.1 through 3 of this Attachment, the Transmission Provider will provide a report and recommend a reconfigured Balanced Portfolio to the Markets and Operations Policy Committee. The Markets and Operations Policy Committee will consider the Transmission Provider s report and recommendation, and will provide its own recommendation (along with the Transmission Provider s report and recommendation) to the SPP Board of Directors. Based upon these recommendations, the SPP Board of Directors shall take action regarding reconfiguration of the Balanced Portfolio. V. Other Network Upgrades A. Sponsored Upgrades The Directly Assigned Upgrade Cost of a Sponsored Upgrade shall be borne voluntarily by the Project Sponsor. The Project Sponsor shall execute an Agreement for Sponsored Upgrade in which it agrees to bear these Directly Assigned Upgrade Costs. In the Agreement, the Project Sponsor shall elect to pay for the Sponsored Upgrade by (1) a lump sum payment or (2) periodic charges calculated in accordance with Commission policy (both hereafter referred to as Project Sponsor s Payment ). Such periodic charges shall be paid on a monthly basis over a twenty year period unless a different frequency and/or shorter term is established in the Agreement for Sponsored Upgrade. The present value of the lump sum or the stream of periodic charges over the term of the paymentsproject Sponsor s Payment shall equal the present value of the projected annual revenue requirements of the Sponsored Upgrade over a twenty year plant life. The annual revenue requirements of the facility Sponsored Upgrade shall be calculated by 43 of 90

156 44 of 90 Southwest Power Pool Original Sheet No FERC Electric Tariff Fifth Revised Volume No. 1 multiplying the levelized fixed charge rate of the Transmission Owner, based on full depreciation over a 20 year plant life and including operating and maintenance expenses and any applicable tax consequences, by the nondepreciated actual cost of the facilitysponsored Upgrade. The Transmission Provider shall file the Agreement initially utilizing good faith estimates of the construction costs for the assigned upgrade. Upon completion of the Sponsored Upgrade, the Transmission Provider shall true up the Directly Assigned Upgrade Costs to the actual construction costs as appropriate and calculate the Project Sponsor s Payment. In addition, the Directly Assigned Upgrade Cost of the Sponsored Upgrade shall be reduced as provided in Section VII of this Attachment J and by any revenue credits granted to a Transmission Owner for the use of the Sponsored Upgrade., as provided in Section I.3 of Attachment Z2. The Project Sponsor shall receive transmission revenue credits in accordance with Attachment Z2. [Does there need to be a sentence or two regarding charging Network Customers for new and/or increased uses similar to what is in Attachment J?] B. Service Upgrades The cost of a Service Upgrade shall be allocated in accordance with Attachment Z1 to this Tariff. The Transmission Customer shall receive transmission revenue credits in accordance with Attachment Z2. C. Generation Interconnection Related Network Upgrades The cost of a generation interconnection related Network Upgrade shall be allocated in accordance with Attachment V to this Tariff. The Interconnection Customer shall receive transmission revenue credits in accordance with Attachment V. 44 of 90

157 45 of 90 Southwest Power Pool First Revised Sheet No. 234 FERC Electric Tariff Superseding Original Sheet No. 234 Fifth Revised Volume No. 1 VI. VII. D. Zonal Reliability Upgrades 1. The cost of Zonal Reliability Upgrades (i) included in the 2005 SPP Transmission Expansion Plan and (ii) placed in service prior to January 1, 2008 shall be allocated in accordance with Section III to this Attachment. 2. The cost of all other Zonal Reliability Upgrades shall be includable in the applicable Zonal Annual Transmission Revenue Requirement. Reserved Treatment of Upgrades that Permit Deferral or Displacement of Network Upgrades A. Deferred Base Plan Upgrade, Balanced Portfolio, Zonal Reliability Upgrade, or Service Upgrade In the case of a Base Plan Upgrade, upgrade that is part of an approved Balanced Portfolio, Zonal Reliability Upgrade, or Service Upgrade that may be deferred as a result of the Network Upgrade ( Deferred Upgrade ), the achievable Accredited Revenue Requirements shall be equal to the time value of the affected Transmission Owner s(s ) revenue requirement(s) for the Deferred Upgrade over the period of the deferral, calculated as follows: Issued by: L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: March 28, 2008 Effective: May 27, of 90

158 46 of 90 Southwest Power Pool First Revised Sheet No. 235 FERC Electric Tariff Superseding Original Sheet No. 235 Fifth Revised Volume No A Transmission Owner s annual revenue requirement for a Deferred Upgrade shall be determined using the same method as is used by the Transmission Owner to calculate its revenue requirement for transmission facilities for other purposes, but applying that method to the projected incremental investment in the Deferred Upgrade. 2. The time value of the deferral shall be calculated by discounting to present value the accredited annual revenue requirements for each individual year in the deferral period and summing the resulting values. For each individual year in the deferral period, the time value of the deferral will be determined by discounting the annual revenue requirement for that year first from January 1 of that year and then from December 31 of that year, summing the two resulting values, and dividing by two. For any partial year encompassed by the deferral period, the time value of the deferral shall be calculated in the same manner as indicated in the immediately preceding sentence, except that the resulting value will be pro-rated based on the number of months in the partial year divided by 12. B. Displaced Base Plan Upgrade, Balanced Portfolio, Zonal Reliability Upgrade, or Service Upgrade In the case of a Base Plan Upgrade, upgrade that is part of an approved Balanced Portfolio, Zonal Reliability Upgrade, or Service Upgrade that may be displaced as a result of the Network Upgrade ( Displaced Upgrade ), the achievable Accredited Revenue Requirements shall be equal to the time value of the affected Transmission Owner s(s ) revenue requirement(s) for the Displaced Upgrade over the expected service Issued by: L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: March 28, 2008 Effective: May 27, of 90

159 47 of 90 Southwest Power Pool First Revised Sheet No. 236 FERC Electric Tariff Superseding Original Sheet No. 236 Fifth Revised Volume No. 1 life of the facility that is displaced. The methodology for calculating the Accredited Revenue Requirements shall be the same as set forth in Section VII.B. of this Attachment, except that the expected service life of the facility shall be substituted for the deferral period in all instances. C. Accredited Revenue Requirements To the extent a Network Upgrade defers or displaces the need for a Base Plan Upgrade, an upgrade that is part of an approved Balanced Portfolio, a Zonal Reliability Upgrade, or a Service Upgrade the Transmission Provider shall calculate the Accredited Revenue Requirements that are achievable due to such upgrade. The Accredited Revenue Requirements shall be based on the estimated project costs for the approved upgrade which is deferred or displaced. 1. If such Network Upgrade defers or displaces the need for a Base Plan Upgrade associated with a new or changed Designated Resources for which there are Directly Assigned Upgrade Costs, the Accredited Revenue Requirements related to Base Plan Upgrade charges shall only include the costs that are allocated to the Base Plan Zonal Annual Transmission Revenue Requirement and the Base Plan Region-wide Annual Transmission Revenue Requirement. 2. If such Network Upgrade defers or displaces the need for an upgrade that is part of an approved Balanced Portfolio, the Accredited Revenue Requirements related to Balanced Portfolio charges shall only include the costs that are allocated to the Balanced Portfolio Region-wide Annual Transmission Revenue Requirement. 3. If such Network Upgrade defers or displaces the need for a Zonal Reliability Upgrade, the Accredited Revenue Requirements related to Zonal Reliability Upgrade charges shall only include the costs that are assigned to the Zonal Annual Transmission Revenue Requirement. 4. If such Network Upgrade defers or displaces the need for a Service Upgrade required to provide Long-Term Firm Point-to-Point Transmission Issued by: L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: March 28, 2008 Effective: May 27, of 90

160 48 of 90 Southwest Power Pool FERC Electric Tariff Fifth Revised Volume No. 1 Original Sheet No. 234A Service, the Accredited Revenue Requirements related to the transmission service charges shall only include the expected increase in revenue that can be distributed through Section II.C of Attachment L to this Tariff, for service under Schedule 7, as a result of displacement or deferral of the Service Upgrade. D. Assignment and Recovery of Accredited Revenue Requirements 1. For Network Upgrades, other than upgrades included in a Balanced Portfolio, that defer or displace the need for a Base Plan Upgrade, an upgrade that is part of an approved Balanced Portfolio, a Zonal Reliability Upgrade or a Service Upgrade: i. The entity responsible for paying the cost of the Network Upgrade shall be responsible for any positive difference between the present value of the total costs for its upgrade and the present value of the Accredited Revenue Requirements. ii. The Accredited Revenue Requirements of the deferred or displaced upgrades shall be recovered through charges specified in: a. Section III.A of this Attachment for deferred or displaced Base Plan Upgrades; b. Section IV of this Attachment for deferred or displaced upgrades associated with a Balanced Portfolio; 48 of 90

161 49 of 90 Southwest Power Pool Original Sheet No FERC Electric Tariff Fifth Revised Volume No. 1 c. Section V.D of this Attachment for deferred or displaced Zonal Reliability Upgrades; and d. Section V.B. of this Attachment for deferred or displaced Service Upgrades. iii. The calculations for determining the Accredited Revenue Requirements shall be filed with the Commission by the Transmission Provider prior to the imposition of any charges or credits hereunder. 2. The costs of the upgrades included in an approved Balanced Portfolio that defer or displace the need for a Base Plan Upgrade, a Zonal Reliability Upgrade, or a Service Upgrade shall be included in the Balanced Portfolio Region-wide Annual Transmission Revenue Requirement and shall be recovered through the Region-wide Charge. i. The costs of a Network Upgrade that is deferred or displaced by the upgrades included in an approved Balanced Portfolio shall not be recovered through the original recovery mechanism for such upgrade. ii. In the evaluation of the benefits of the Balanced Portfolio as specified in Section IV.6.d of Attachment O to this Tariff, the Accredited Revenue Requirements associated with the deferred or displaced Base Plan Upgrade(s), Zonal Reliability Upgrade(s) and Service Upgrade(s) shall be treated as benefits to the Zones to which those Accredited Revenue Requirements are distributed or would have been otherwise assigned or recovered as specified in: a. Section III.A of this Attachment for deferred or displaced Base Plan Upgrades; b. Section V.D of this Attachment for deferred or displaced Zonal Reliability Upgrades; and c. Section II.C of Attachment L for service under Schedule 7 for deferred or displaced Service Upgrades. 49 of 90

162 50 of 90 Southwest Power Pool First Revised Sheet No. 237 FERC Electric Tariff Superseding Original Sheet No. 237 Fifth Revised Volume No. 1 VIII. Uncompleted Network Upgrades The costs of Network Upgrades that are not completed through no fault of the Transmission Owner charged with construction of the upgrades shall be handled as follows: If a proposed Network Upgrade was accepted and approved by the Transmission Provider, the Transmission Provider shall develop a mechanism to recover such costs and distribute such revenue on a case by case basis. Such recovery and distribution mechanism shall be filed with the Commission. The Transmission Owner(s) that incurred the costs shall be reimbursed for those costs by the Transmission Provider. These costs shall include, but are not limited to: the costs associated with attempting to obtain all necessary approvals for the project, study costs, and any construction costs. Issued by: L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: March 28, 2008 Effective: May 27, of 90

163 51 of 90 Southwest Power Pool, Inc. MARKETS AND OPERATIONS POLICY COMMITTEE Recommendation to the Board of Directors October 28, 2008 Organizational Roster The following members represent the Market Working Group: Richard Ross, AEP, Chairman Gene Anderson, OMPA James Liao, WFEC Gary Clear, OG&E Jessica Collins, Xcel Energy Robert Janssen, Redbud Energy Patricia Denny, KCPL Rick McCord, EDE Tambra Offield, ETEC Max Sherman, Aquila Angela Easton, Calpine John Stephens, Springfield MO Grant Wilkerson, Westar Keith Sugg, AECC Emily Davis, SPP, Secretary Background FERC Orders, member questions or a general need to enhance the level of detail provided in the Market Protocols have resulted in a desire to modify the Market Protocols pursuant to the Protocol Revision Request process. A meeting was held by the MWG on July 22 23, August and September 16 17, 2008 to discuss specific proposed changes necessary to respond to the FERC order or that MWG feels are necessary. Analysis Please see the enclosed PRR recommendation reports approved by the MWG which are also listed below and grouped for recommendation purposes. In the event any comments are submitted on the MWG recommendation reports prior to the distribution of the MOPC meeting materials they will be included for consideration by the MOPC during its discussion. Recommendation The MOPC recommends the Board of Directors adopt the approved Protocol Revision Requests for incorporation into the Market Protocols. Page 1 of 2 51 of 90

164 52 of 90 PRR Number Description Vote No Votes MWG Meeting MOPC Meeting 184 PRR 113 was approved to provide for Profiled Ramp Rates and additional Minimum and Maximum Capacity Limits on the Resource Plans. PRR 113 only reflected changes to Section 3 of the Protocols specifically around the Resource Plan. Operational usage of the data and references to those data items in other sections of the Protocols were not updated causing conflicts within the document. System design of the Profiled Ramp Rate capability is also more flexible than originally submitted in PRR 113. This PRR will modify the ramp rate section to reflect system development enhancements. Approved (one abstention Westar) 16-June Unanimously Approved October 14-15, The Removal from Dispatch section actually reduces available ramp capability and capacity availability. This adversely impacts market operations yet provides little or no incentive to Market Participants to follow dispatch instruction Approved 1- no vote (Westar) 16-Sept Unanimously Approved October 14-15, 2008 Action Requested: Approval of PRR Recommendations for incorporation into the Market Protocols. Page 2 of 2 52 of 90

165 53 of 90 PRR Number Timeline (Normal or Urgent) 184 PRR Recommendation Report PRR Title Supplemental Language for PRR 113 Urgent Recommended Action Approve Impact Analysis Needed (Yes or No) Protocol Section(s) Requiring Revision (include Section No., Title and Version) Revision Description PRR Recommendation (indicate whether all segments were present for the vote, and the segment of parties that voted no or abstained) 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) No Section 3.2, 6.6.2, 7.1, 8.5.1, 9.1, 9.2.5, 9.4, and PRR 113 was approved to provide for Profiled Ramp Rates and additional Minimum and Maximum Capacity Limits on the Resource Plans. PRR 113 only reflected changes to Section 3 of the Protocols specifically around the Resource Plan. Operational usage of the data and references to those data items in other sections of the Protocols were not updated causing conflicts within the document. System design of the Profiled Ramp Rate capability is also more flexible than originally submitted in PRR 113. This PRR will modify the ramp rate section to reflect system development enhancements. Approved in the June 17-18, 2008 MWG meeting with one abstention (Westar). Unanimously approved in the June 26, 2008 ORWG conference call. Name Company Original Sponsor Jarrett Friddle Utilicast on behalf of SPP PRR184_Recommendation_Report Page 1 of of 90

166 54 of 90 PRR Recommendation Report Comment Author Comments Received Comment Description Proposed Protocol Language Revision 3.2 Contents The Resource Plan covers a seven-day horizon (with hourly detail) beginning with the Operating Day. See SPP Criteria Appendix 7 and XML Specifications for additional details. Specifically, the Resource Plan contains entries for each Resource for each hour of the seven day horizon similar to the following: Resource ID - Unique identifier for Resource in SPP Market Resource Type - GEN-Generation, CLD-Controllable Load, or PLT-Plant Planned Megawatts - Anticipated dispatch of unit independent of energy imbalance deployment. This value is within the dispatchable range of the Resource except during periods of Start Up and Shut Down. Minimum Capacity Operating Limit - Resource physical minimum sustainable output for each Operating Hour ( MinMW ) Minimum Economic Capacity Operating Limit - Resource economic minimum output selected by Market Participant for each Operating Hour ( MinEconMW ). Must be equal to or greater than value provided for Minimum Capacity Operating Limit. Minimum Emergency Capacity Operating Limit - Resource physical minimum emergency output for each Operating Hour ( MinEmerMW ). Must be equal to or less than value provided for Minimum Capacity Operating Limit.[EED1] Maximum Economic Capacity Operating Limit - Resource economic maximum output selected by Market Participant for each Operating Hour ( MaxEconMW ). Must be equal to or less than value provided for Maximum Capacity Operating Limit. PRR184_Recommendation_Report Page 2 of of 90

167 55 of 90 PRR Recommendation Report Maximum Emergency Capacity Operating Limit - Resource physical maximum emergency output for each Operating Hour ( MaxEmerMW ). Must be equal to or greater than value provided for Maximum Capacity Operating Limit. Maximum Capacity Operating Limit - Resource physical maximum sustainable output for each Operating Hour ( Max MW )[EED2] Ramp Rate - Rate at which Resource can change output in MW/min Market Participants will submit their Ramp Rates through a segmented profile. The profile will require at least 1 segment and may have up to n segments where n will be defined by SPP, initially set to 10. o Breakpoint Limit 1 Resource MW output at which segment 1 Ramp Rates changes from Block 1 Rates to Block 2 Rateswill apply. If the value is not less than or equal to actual measured MW during deployment, the values in segment 1 will apply back to the actual measured MW. o Block 1 Rate Up Rate at which Resource can change output upward in MW/min at output levels less greater than or equal to Breakpoint Limit 1. o Block 1 Rate Down Rate at which Resource can change output downward in MW/min at output levels greaterless than or equal to Breakpoint Limit 1. o Block 1 Rate Emergency Rate at which Resource can change output upward or downward in MW/min at output levels greaterless than or equal to Breakpoint Limit 1 during an emergency. o Breakpoint Limit n Resource MW output at which Ramp Rate changes from previous segment values to segment n values. o Block 2n Rate Up - Rate at which Resource can change output upward in MW/min at output levels greater than or equal to the Breakpoint Limit n1 and less than Breakpoint Limit 2. o Block 2n Rate Down - Rate at which Resource can change output downward in MW/min at output levels greater than or equal to the Breakpoint Limit n1 and less than Breakpoint Limit 2. o Block 2n Rate Emergency Rate at which Resource can change output upward or downward in MW/min at output levels greater than the Breakpoint Limit 1 and less than Breakpoint Limit 2 during an emergency. oblock 3 Rate Up - Rate at which Resource can change output upward in MW/min at PRR184_Recommendation_Report Page 3 of of 90

168 56 of 90 PRR Recommendation Report output levels greater than the Breakpoint Limit 2. oblock 3 Rate Down - Rate at which Resource can change output downward in MW/min at output levels greater than the Breakpoint Limit 2. oblock 3 Rate Emergency Rate at which Resource can change output upward or downward in MW/min at output levels greater than the Breakpoint Limit 2 during an emergency.[eed3] Resource Status: o Available Resource is online and available for SPP Deployment. o Available Quick Start Resource is off line, available for SPP deployment, capable of closing the breaker, synchronizing to the grid, and reaching the operating level consistent with the dispatch instruction.[eed4] o Unavailable Resource is offline and unavailable for SPP Deployment or other uses. o Supplemental Resource is offline and available for satisfying Supplemental Reserve requirements. The Resource will NOT be dispatched by the MOS system. o Manual - Resource is (a) Not capable of following Dispatch Instructions, either by virtue of: (1) being an Intermittent Resource; or (2) undergoing a Resource Test, Startup, or Shutdown Mode; and (b) Not capable of adhering to a Schedule either by virtue of: (1) being an Intermittent Resource; or (2) operating in Resource Test, Startup, or Shutdown Mode where the inception, termination, or duration of the testing, Start-up or Shut-down process cannot be confirmed or predicted. Resources in manual status will be permitted to report Ancillary Services if the limitations on their ability to follow Dispatch Instructions or adhere to their Schedules do not preclude them from providing said Ancillary Services. o Self-dispatched Resource is online and unavailable for SPP Deployment. Note that the meaning and format and current required fields of this submission are fully defined in the XML Specification document. The Resource Plan may not be the only source of Resource data required by SPP, in its roles as the Regional Reliability Coordinator and Transmission Service Provider, for the purposes of maintaining system reliability and granting transmission service. Market Participants with registered Resources, or the Balancing Authorities within which such Resources are located, may PRR184_Recommendation_Report Page 4 of of 90

169 57 of 90 PRR Recommendation Report be requested to provide to SPP additional Resource information beyond that contained in the Resource Plan through mechanisms other than the Portal or API, as deemed necessary by SPP and consistent with its authority as the Regional Reliability Coordinator and Transmission Service Provider.[EED5] 1.1.1Resource Scheduling Requirements The sum of Market Participant schedules sourcing from a Self-Dispatch Resource shall not exceed the MaxEmerMW of the Resource submitted in the Resource Plan for any Settlement Interval. Each Market Participant is required to provide sufficient energy available to SPP to serve the MP s obligations at all times. MPs must satisfy their energy obligations by scheduling energy from third parties, causing its Self Dispatched Resource to operate at Scheduled Megawatt levels and/or making its Resources available to SPP for dispatch with sufficient dispatchable operating range such that in aggregate they are capable of producing sufficient energy to be capable of serving the MPs obligations at all times. MPs must satisfy their ancillary services obligations, including operating reserve requirements, by submitting an Ancillary Services Plan which demonstrates their ancillary service requirements are being met. Examples of Satisfying Energy Requirements A Market Participant with an obligation of 500 MW at Settlement Location(s) in a particular hour and two Resources, each having a Mminimum operatingeconmw limit of 60 MW and maximum operatingmaxeconmw limit of 300 MW, could do any of the following: (1) 100% Self Dispatch - Self Dispatch both of its Resources, indicate it intends to operate its Resources on its Resource Plan at an aggregate of 500 MW and generate in real time 500 MW, consistent with the schedules. The MP must also schedule an aggregate of 500 MW from its Resource Settlement Locations to meet its Energy Obligations. (2) 100 % Offered for dispatch - Make both of its Resources available for SPP dispatch such that SPP can calculate economic base points within the their operating range of 60 MW to 300 MW on each unit. While not explicitly required, the MP could also choose to schedule from its Resource Settlement Locations. (3) Hybrid - Make one of its Resources available for SPP dispatch such that SPP can calculate economic base points within its operating range of 60 MW to 300 MW. Self Dispatch its other Resource by indicating on its Resource Plan that it intends to operate that Resource at some level at or above 200 MW and generate in real time consistent with that indication. The MP must also schedule 200 MW from the Self-Dispatched Resource Settlement Location. Self-Dispatch of the second unit at or above 200 MW is required so that the remaining requirements can be PRR184_Recommendation_Report Page 5 of of 90

170 58 of 90 PRR Recommendation Report covered by the Resource that is made available for SPP dispatch. While not explicitly required, the MP could also choose to schedule from its offered Resource Settlement Locations Supply Adequacy The supply adequacy analysis will be based on Load forecast information, Resource Plans, Ancillary Service Plans, and schedules received from Market Participants. SPP will determine each Market Participant s Energy Obligation. A Market Participant s Energy Obligation shall be computed as follows: Load forecast + scheduled sales scheduled purchases SPP will compare the Market Participant s Energy Obligation against the sum of its Max EconDispatchable MW and the sum of its Min DispatchableEcon MW calculated from its Resource Plan and Ancillary Service Plan as defined in Section 98.4 of these Protocols. A Market Participant shall be deemed as having insufficient energy supply if the following condition is met: sum of Max EconDispatchable MW < Energy Obligation A Market Participant shall be deemed as having too much energy supply if the following condition is met: sum of Min EconDispatchable MW > Energy Obligation If either condition is met, the Market Participant is deemed to have inadequate supply. SPP will then compare the aggregation of the Market Participants Resource Plans and schedules by each Balancing Authority Area within the EIS Market footprint against SPP s Load forecast and Ancillary Service requirements for each Balancing Authority Area. If this analysis indicates that a particular Balancing Authority Area has inadequate supply, SPP will notify the Market Participant(s) deemed inadequate and its host Balancing Authority. This information shall be submitted via the Portal or Application Program Interface (API). The Market Participant shall resolve this energy supply inadequacy by modifying its Load Forecast, Resource Plan and/or schedules. The Market Participant shall make the appropriate modifications by 1700 day prior to the OD for any energy supply inadequacy revealed by the daily study. The Market Participant shall make the appropriate modifications no later than 45 minutes prior to the Operating Hour (OH) for any energy supply inadequacy revealed by the hourly study. SPP shall provide a copy of any modified Resource Plans and/or schedules to the affected Balancing Authorities. In the event a Market Participant does not resolve the issue and it contributes to a reliability problem at or prior to real-time, the Market Participant will be subject to interruption of Load, interruption of Resources, curtailment of schedules and or manual deployment of Resources, if deemed necessary. All instances where the Market Participant fails to resolve an identified issue at or prior to real-time and it contributes to a reliability problem will be reported to FERC on an after-the-fact basis. PRR184_Recommendation_Report Page 6 of of 90

171 59 of 90 PRR Recommendation Report Resource Operating Tolerance A Resource operating tolerance will be defined based on an acceptable amount of dispatching error with an adjustment for regulation services being maintained on the Resource. The operating tolerance is intended allow SPP to maintain the efficiency of the EIS dispatch and provide additional financial incentives for Market Participants to cause their Resources to perform, whether offered for SPP Dispatch or Self Dispatched, within an acceptable range. The portion of the operating tolerance based on the Resource s Dispatch InstructionCapability will be the acceptable dead band percentage multiplied by the Dispatch InstructionMaxEconMW and limited to a minimum of 5 MW and maximum of 25 MW. A Resource will be considered to be operating within acceptable Resource operating tolerance so long as its current operating level is between the high and low operating tolerance limits defined as follows: RH i = Max (5, Min ((EOL i * DBP), 25)) + REGUP o RL i = Max (5, Min ((EOL i * DBP), 25)) + REGDN o Where: RH= RL= EOL = DBP = REGUP o = REGDN o = i = Resource High operating tolerance or over generation limit (MW) Resource Low operating tolerance or under generation limit (MW) The Expected Operating Level for the Resource in megawatts as communicated in the Transmission Provider s dispatch instruction. Dead Band Percentage for all Resources is initially set to 10 % above and below the Dispatch Instruction (EOL)Resource EconMaxMW, but is subject to change by subsequent Protocol Revision Request. Regulation Up service being maintained on the Resource as indicated in the Ancillary Service Plan (MW) for the Operating Hour. Regulation Down service being maintained on the Resource as indicated in the Ancillary Service Plan (MW) for the Operating Hour. Dispatch interval within Operating Hour. PRR184_Recommendation_Report Page 7 of of 90

172 60 of 90 PRR Recommendation Report MaxEcon CapacityMW MaxDispatchable CapacityMW Acceptable Operating Range Dispatch Instruction + RH Dispatch Instruction Dispatch Instruction - RL MinDispatchable CapacityMW MinaxEcon CapacityMW 9.1 Introduction SPP shall determine the least costly means of obtaining energy to serve the next increment of Load at each injection/withdrawal node defined in the State Estimator for SPP and each interface bus between SPP and an adjacent Control Area using its Scheduling, Pricing, and Dispatch (SPD) program. The following limiting factors are employed by the SPD program in determining the least costly means of serving the next increment of Load: the system conditions described by the most recent power flow solution produced by the State Estimator program, unit parameters provided in resource plans, energy offers, and binding transmission constraints. In certain situations, as described more fully below, SPP may dispatch the system in a manner that does not fully enforce all such limiting factors by applying Violation Relaxation Limits (VRLs) in SPD. The SPD program uses an incremental linear optimization method to minimize energy costs. In performing this calculation, SPP shall use the EIS offer(s) that can serve the Load at a bus at the lowest cost and shall assume Self Dispatched Resources will be operating at their scheduled Megawatt level indicated on the RTO_SS schedules and the Native Load Scheduler at the end of PRR184_Recommendation_Report Page 8 of of 90

173 61 of 90 PRR Recommendation Report each Dispatch Interval. The dispatch does not take into account the differences in loss factors between Resources when calculating dispatch instructions. This deployment determines the dispatch instructions for Resources that have offered to provide EIS. Resources that have elected to be dispatched by SPP will have the entire MW capability available for SPP dispatch, subject to the MaxEconMW, MinEconMW, Ramp Rate and Ancillary Service parameters specified by the Market Participant in the Resource and Ancillary Service Plans. The dispatch instructions on the Resources are based upon the Offer Curve, Resource Plan, and Ancillary Services Plan Real-Time Deficit and Excess condition in Dispatchable Ranges A real-time deficit condition occurs when SPP does not have adequate dispatchable resources to meet real-time imbalance energy demand. A real-time excess condition occurs when SPP is unable to meet real-time imbalance energy demand without violating the minimum operating limit restrictiondispatchable range of dispatchable resources. SPP shall address these conditions by adjusting the NSI values of that Balancing Area(s) where the Market Participant causing the deficit or excess condition. Identification of MP causing Deficit or Excess condition In the Day Ahead Simultaneous Feasibility Test (DASFT) and the intra-operating day capacity adequacy tests performed for each operating hour, SPP shall evaluate all MP s forecast load and the sufficiency of offered EIS resources. SPP will estimate each MP s real-time EIS demand based on the information available at the time these checks are performed. SPP shall also evaluate whether each MP have has arranged for adequate capacity to meet their real time loads obligation, if any. MPs within that BA(s) shall be notified that an excess or deficit condition exists within the BA, and SPP will assist the BA to maintain reliable operations. BA(s) shall coordinate with SPP all action necessary according to Attachment AN of the SPP OATT. Declaration of Deficit condition SPP shall evaluate, on a forward looking basis, at the time it calculates the dispatch instruction for the applicable dispatch interval, whether it is able to meet the EIS demand of of the Market footprint for that dispatch interval. If SPP determines that it is unable to meet the anticipated EIS demand for that dispatch interval because of a lack of deliverable EIS resource(s), it will declare a deficit condition for the EIS Market. At this time, SPP shall also determine which Balancing Areas are specifically deficient. SPP shall post a notification to all BAs of the Market deficit condition. SPP shall also send notice of deficit conditions to all MPs within the deficient BA(s) Declaration of Excess condition SPP shall evaluate, on a forward looking basis, at the time it calculates the dispatch instruction for the applicable dispatch interval, whether it is able to meet the EIS demand of the Market footprint for that dispatch interval. If SPP determines that it is unable to meet the anticipated PRR184_Recommendation_Report Page 9 of of 90

174 62 of 90 PRR Recommendation Report EIS demand for that dispatch interval because of it would have to violate the minimum minimum operating dispatchable range of deliverable EIS resource(s), SPP will declare an excess condition for the EIS market and notify all Balancing Areas. SPP shall also identify the specific BA(s) that will be affected by the excess condition, and send notifications to all MP within those BA(s) of that excess condition Data provided to BA and MP Notification At the time SPP determines if an excess of deficit condition exists within a Balancing Area, SPP shall provide the following information to the Balancing Authority. Dispatch Interval MW amount of anticipated mismatch MP net Schedule total and net Deployment Instructions Estimated NSI bias amount NSI Adjustment For those Balancing Authorities where excess or deficit condition exists, an NSI adjustment totaling the shortage or excess demand will be shared pro-rata in real-time depending on how over or short each Balancing Area is estimated to be. SPP will coordinate the NSI bias and BA actions to minimize the effect on reliability and the BA s ability to regulate and/or utilize spinning reserve(s), and to avoid the need to declare an OEC or EEA. Deficit Condition If in real-time SPP has a generation dispatch deficit, the deficit MW will be distributed among all BAs with generation shortage to be reflected in their NSI. The adjusted BA NSI for BAs with capacity shortage is equal to: Total Balancing Authority Area (BAA) Resource Dispatched MW (-) BAA Load Forecast (+) BAAs pro rata share of the system shortage BA s with shortage will be identified as having a positive value for: BAA Load Forecast (-) BAA Total Maximum Dispatchable Generation (+) BAA Net Scheduled Export In this event, the LIP of all resources that were identified as AGC resources in the Balancing Authorities A/S plan, will be set to the highest SPP wide cleared offer Excess Condition If in real-time SPP has a generation dispatch excess, the excess MW will be distributed among BAs with excess energy to be reflected in their NSI. The adjusted BA NSI for BAs with generation excess is equal to: Total BAA Resource Dispatched MW (-) BAA Load Forecast (+) BAAs pro rata share of the system excess PRR184_Recommendation_Report Page 10 of of 90

175 63 of 90 PRR Recommendation Report BAs with excess will be identified as having negative value for: BAA Load Forecast (-) BAA Total Minimum Dispatchable Generation (+) BAA Net Scheduled Export In this event, the LIP of all resources that were identified as AGC resources in the Balancing Authorities A/S plan will be set to the lowest SPP wide cleared offer. Use of Data Data from the Offer Curves, Resource Plan, and Ancillary Services Plans are used, along with the State Estimator, to calculate the dispatch instruction. If a Resource indicates availability for SPP dispatch control through the Resource Plan, the Security Constrained Economic Dispatch requests movement within the dispatchable range. If a resource is in Self-dispatched status, then MinDispatchableMW = MaxDispatchableMW = the sum of the schedules sourcing from that resource. For a unit in Available Quick Start status, while the Resource breaker is open, the SPP MOS will treat the Resource just like other Resources Available for SPP Dispatch with a Minimum Economic Capacity Operating Limit of zero (0) MW. For a unit in Available Quick Start status, when the Resource breaker is closed, the SPP MOS will treat the Resource just like other Resources Available for SPP Dispatch with a Minimum Economic Capacity Operating Limit as indicated on the Resource Plan.[EED6] This The dispatchable range for resources in Available status is calculated using the data from the Resource Plan and reserve designations (a.k.a. Ancillary Service Plan), as illustrated below: MinDispatchableMWEcon i = MinEconMW o + REGDN o MaxEcon i MaxDispatchableMW i = MaxEconMW o REGUP o MAX (SPIN o + SUPP o - RSS i, 0) Where: MinEcon i MinDispatchableMW i = Minimum Economic Limit of Dispatchable Range (MW) MaxDispatchableMWEcon i = Maximum Economic Limit of Dispatchable Range (MW) PRR184_Recommendation_Report Page 11 of of 90

176 64 of 90 PRR Recommendation Report MinEconMW o = Minimum Economic Capacity Operating Limit (MW) as indicated on the Resource Plan for the hour of the Dispatch Interval (MW) MaxEconMW o = Maximum Economic Capacity Operating Limit (MW) Limit as indicated on the Resource Plan for the hour of the Dispatch Interval (MW) SPIN o = Spinning Reserves being maintained on the Resources as indicated in the Ancillary Services Plan for the hour of the Dispatch Interval (MW) SUPP o = Supplemental Reserves being maintained on the Resource as indicated in the Ancillary Services Plan for the hour of the Dispatch Interval (MW) REGUP o = Regulation Up service being maintained on the Resource as indicated in the Ancillary Service Plan for the Operating Hour (MW). REGDN o = Regulation Down service being maintained on the Resource as indicated in the Ancillary Service Plan for the Operating Hour (MW). RSS i = Energy scheduled, through the Reserve Sharing System, from the reserves being maintained on the Resources in response to an ARS event for the Dispatch Interval (MW), as defined in Section 6 o = Operating Hour i = Dispatch interval within Operating Hour. SPIN/SUPP DRS URS 0 MW Dispatchable Range Maximum Capability Min MW Max MW Min Econ MW Max Econ MW PRR184_Recommendation_Report Page 12 of of 90

177 65 of 90 PRR Recommendation Report SPIN/SUPP DRS URS Dispatchable Range MinMW MinDisp MW MaxDisp MW MaxMW MinEmer MW MinEcon MW MaxEcon MW MaxEmer MW Dispatch instructions are generated within the range titled Dispatchable Range. Operators of Resources use the dispatch instructions to operate their Resources. SPP dispatch instructions will not deploy below the MinDispatchable MW, nor above the MaxDispatchable MW. The Control Area operators regulate the Control Area based on the provided NSI. Calculation of Settlement Location Prices for Resources The price used for settlement of Resources is the LIP at the Resource s Settlement Location. The LIP is the offer price to meet the next MW in a security constrained economic dispatch. The Settlement Location price will be the calculated LIP. For each Settlement Interval: SUM (LIP SLDI ) / # DI per Settlement Interval SL = Settlement Location DI = Deployment Interval Setting Price In general, a Resource sets price when its output meets the two following conditions. PRR184_Recommendation_Report Page 13 of of 90

178 66 of 90 PRR Recommendation Report 1. The Resource is under SPP dispatch and is deployed. 2. The Resource is not limited in its ability to change output to comply with economic dispatch of EIS energy. Limitations may include the Resource operating at the minimum or maximum of its dispatchable range, maximum, operating at its minimum, ramp rate limitations, other Resource operating limitations, transmission constraints, etc. A Resource that is not free to change output to move along its offer curve in response to SPP s dispatch instructions will not set price Tolerance Levels and Substitution Criteria SCADA - 5 minute interval value High Tolerance Band - Greater than 120% of the Resource Plan MaxEmerMW Substitution value Dispatch Instructions (results in zero URD) Low Tolerance Band Less than Minimum Operating Capacity Substitution value Dispatch Instructions (results in zero URD) Dispatch Instruction - 5 minute interval value High Tolerance Band - Greater than 120% of the Resource Plan MaxEmerMW Substitution value Use SCADA value (results in zero URD) Low Tolerance Band Less than Zero Substitution value Use SCADA value (results in zero URD) Resource Meter Data High Tolerance Band - Trigger value supplied by meter agent/market Participant Substitution value Schedule value Low Tolerance Band Auxiliary negative value supplied by meter agent/market Participant Substitution value Schedule value Load Meter Data High Tolerance Band - 150% of previous year annual peak Substitution value Schedule value Low Tolerance Band Zero value Substitution value Schedule value Interchange Meter Data High Tolerance Band - Trigger value supplied by meter agent/market Participant Substitution value NSI Low Tolerance Band Trigger value supplied by meter agent/market Participant Substitution value NSI Tariff Changes 1.1.7a Economic Dispatchable Maximum Limit PRR184_Recommendation_Report Page 14 of of 90

179 67 of 90 PRR Recommendation Report A Resource s economic maximum output selected by Market Participant for each Operating Hourphysical maximum sustainable capacity limit, as identified in the Resource Plan, reduced by the sum of the megawatt amounts of Schedule 3, Schedule 5 and Schedule 6 Service assigned to that Resource, as identified in the Ancillary Services Plan. For a Self-dispatched resource, the Dispatchable Maximum Limit = the sum of the schedules sourcing from that resource b Economic Dispatchable Minimum Limit A Resource s economic minimum output selected by Market Participant for each Operating Hourphysical minimum sustainable capacity limit, as identified in the Resource Plan, increased by the megawatt amount of Schedule 3 Service assigned to that Resource, as identified in the Ancillary Services Plan. For a Self-dispatched resource, the Dispatchable Minimum Limit = the sum of the schedules sourcing from that resource Scheduling and Dispatch The Transmission Provider shall evaluate Resource Plans submitted by Market Participants during the Day-Ahead Period and the Hour-Ahead Period in accordance with Sections 2 and 3 of this Attachment. (a) In the Real-Time Period, the Transmission Provider shall dispatch Dispatchable Resources between their Economic Dispatchable Minimum Limit and Dispatchable Economic Maximum Limit to provide Energy Imbalance Service economically on the basis of least-cost, security-constrained economic dispatch and the prices and operating characteristics offered by Market Participants or based upon Manual Dispatch Instructions only during Emergency Conditions where such Emergency Conditions can not be resolved through the process described under Section 4.3 of Attachment AE A Market Participant s Resource Plan shall be submitted according to the following: (a)using the data formats, procedures, and information defined in the Market Protocols. Resource Plans shall be submitted using the data formats and procedures defined in the Market Protocols (b) A Market Participant s Resource Plan shall contain the following information associated with each of that Market Participant s Resources: i. Resource type, either generation, controllable load, or plant; ii. Resource s physical minimum sustainable capacity limit in megawatts per hour for each Operating Hour and physical and maximum sustainable capacity limit in megawatts per hour for each Operating Hour; iii. Resource hourly forecasted generation in megawatts per hour for PRR184_Recommendation_Report Page 15 of of 90

180 68 of 90 PRR Recommendation Report the next seven days; iv. Resource status for SPP dispatch for the next seven days; and v. A planned operating schedule in the absence of a market Between 1300 and 1500 Central Prevailing Time on the day prior to the Operating Day, the Transmission Provider shall perform a review of the operating capacity scheduled in each Market Participant s Resource Plan. This review shall include an assessment of the total operating capacity scheduled in each hour of the next Operating Day and a simultaneous feasibility study to ensure that such operating capacity is deliverable in each hour of the next Operating Day. (a) Supply Adequacy Analysis The inputs to the supply adequacy analyses shall be the load forecasts developed pursuant to Section 2.1 and submitted under Section 2.2, the Resource Plans submitted pursuant to Section 2.2 the energy obligations calculated under Section 2.2 and Ancillary Service Plans submitted pursuant to Section 2.3. The objective of performing the supply adequacy analysis is to ensure there is sufficient operating capacity scheduled so that the Transmission Provider may operate the system reliably to meet the load forecast. For each hour, the Transmission Provider shall determine if each Market Participant s energy obligation as set forth in Section 2.2 is: (i) less than the aggregate of the Economic Dispatchable Maximum Limits; and (ii) greater than the aggregate of the Economic Dispatchable Minimum Limits submitted in its Resource Plan. Similarly, for each Balancing Authority Area, the Transmission Provider shall determine if the Balancing Authority s energy obligation set forth in Section 2.2 is: (i) less than the aggregate of the DispatchableEconomic Maximum Limits; and (ii) greater than the aggregate of the Dispatchable Economic Minimum Limits submitted in all Market Participant Resource Plans in that area. If the Transmission Provider determines there is an Energy Obligation Deficiency or Energy Obligation Excess in any hour of the next Operating Day within a Balancing Authority Area, the Transmission Provider shall immediately notify those Market Participants within that Balancing Authority Area that have an Energy Obligation Deficiency or Energy Obligation Excess, as applicable, in that hour. Such Market Participant shall correct the deficiency or excess and resubmit revised plans and/or schedules to the Transmission Provider by the later of 1700 on the day prior to the Operating Day or two hours following notification by the Transmission Provider. (b) Simultaneous Feasibility Analysis (i) The inputs to the simultaneous feasibility analyses shall be the load forecasts developed pursuant to Section 2.1, the Resource Plans submitted pursuant to Section 2.2, including any applicable Energy Schedules, Offer Curves submitted pursuant to Section 2.5 PRR184_Recommendation_Report Page 16 of of 90

181 69 of 90 PRR Recommendation Report and Ancillary Service Plans submitted pursuant to Section 2.3. The simultaneous feasibility analysis determines the impacts of single transmission facility contingencies on a set of monitored transmission facilities. (ii) To verify that the submitted Resource Plans and applicable Energy Schedules can be implemented reliably, the Transmission Provider shall determine if all constraints identified in the simultaneous feasibility analysis can be resolved through; (i) the simulated dispatch of Dispatchable Resources only; and (ii) simulation of potential impacts that a TLR may have on the constraint as described in the Market Protocols. If such constraints can be resolved, the Transmission Provider shall post a notification on its website identifying the projected constraint and that TLR may be necessary to resolve the issues in Real-Time. (iii) If the Transmission Provider determines through the simultaneous feasibility analysis that the submitted Resource Plans cannot be implemented reliably, the Transmission Provider shall immediately notify the affected Market Participants that their plans are infeasible. The Transmission Provider shall determine each affected Market Participant s responsibility for resolving the infeasibility in accordance with the Market Protocols. Such Market Participants shall revise and resubmit their plans to the Transmission Provider by the later of 1700 on the day prior to the Operating Day or two hours following notification by the Transmission Provider. PRR184_Recommendation_Report Page 17 of of 90

182 70 of 90 PRR Recommendation Report Estimated Impact Analysis SPP Staffing Impacts (across all areas) Previously addressed in PRR 113 SPP Computer System Impacts Previously addressed in PRR 113 SPP Business Function Impacts Previously addressed in PRR 113 PRR184_Recommendation_Report Page 18 of of 90

183 71 of 90 PRR Recommendation Report PRR Number 186 PRR Title Uninstructed Deviation Penalty Charges Timeline Recommendation Action Normal Urgent Provide explanation if urgent is selected Approve Reject Require additional information Defer Refer Impact Analysis Required Yes No Protocol Section(s) Requiring Revision Revision Description Section No Title Removal from Dispatch Protocol Version 8.0a The Removal from Dispatch section actually reduces available ramp capability and capacity availability. This adversely impacts market operations yet provides little or no incentive to Market Participants to follow dispatch instruction. Date of Vote 09/16/08 PRR Recommendation RTWG Review ORWG Review MOPC Recommendation All Segments present for the vote Yes No Segment of Parties that voted No or Abstained Approved with 1 no vote (Westar) in the September 16 17, 2008 MWG meeting. Approved with one abstention in the September 26, 2008 RTWG meeting. Name Company Original Sponsor Alan McQueen Southwest Power Pool, Inc. PRR186_Recommendation_Report Page 1 of 2 71 of 90

184 72 of 90 Comment Author PRR Recommendation Report Comments Received Comment Description Proposed Protocol Language Revision Proposed Protocol Language Revision Removal from Dispatch Any Resource that is available for SPP dispatch and operates outside its Resource operating tolerance for 6 or more consecutive intervals will be considered noncontrollable by SPP dispatch by manually setting the units ramp rate to zero. An XML warning will be issued to the Resource, if operating outside its Operating Tolerance for 3 consecutive dispatch intervals after the 3 rd and subsequent consecutive dispatch intervals. The SPP Market Operators will notify a Market Participant when it takes such actions and upon subsequent notification by the Market Participant of their ability to comply with instructions, the SPP Market Operators will allow the Resource to be controllable by SPP dispatch. Section 4.1 Proposed Tariff Language Revision (c) If a Dispatchable Resource fails to follow the Transmission Provider s dispatch instructions communicated pursuant to Section 4.1(a)(ii) for six consecutive Dispatch Intervals, that Resource shall be considered a Self-Dispatched Resource until such time that the Market Participant Resource owner demonstrates to the Transmission Provider that such Resource is capable of following the Transmission Provider s dispatch instructions. PRR186_Recommendation_Report Page 2 of 2 72 of 90

185 73 of 90 Southwest Power Pool, Inc. RTWG Recommendation to the Markets and Operations Policy Committee October 14-15, 2008 Schedule 2 Organizational Roster The following persons are members of the Regional Tariff Working Group: Dennis Reed, WR (Chair) David Brian, ETEC (Vice-Chair) Bill Dowling, Midwest Energy David Kays, OGE Robert Pennybaker, AEP Bary Warren, EDE Mitch Williams, WFEC Ron Gary, LAFA Mike Proctor, MoPSC Bernie Liu, Xcel Rob Janssen, Redbud Gene Anderson, OMPA Mark Foreman, Tenaska Mike Wise, Golden Spread Charles Locke, KCPL Steve Ferry, Sunflower Robert Shields, AECC Rob Bowser, KEPCo Angela Easton, Calpine Pat Bourne, SPP Gerrud Wallaert, SPP (Secretary) Background and Analysis On December 26, 2008, SPP submitted a revised Schedule 2 which provided for comparable compensation for Reactive Power on a non-discriminatory and comparable basis. FERC required SPP to modify the Schedule 2 provisions to allow for generators to register for reactive compensation through out the year. As a result, SPP filed the tariff language modifications to satisfy the FERC requirement on May 25, During the implementation of the modified Schedule 2 process, several minor tariff language modifications were identified to make Schedule 2 consistent with the most current registration provisions. The RTWG submits the proposed tariff language modifications to correct the tariff language which is inconsistent with the FERC approved Schedule 2 process. Recommendation The RTWG recommends that the MOPC approve the non-substantive tariff language modifications of Schedule 2. Approved: Regional Tariff Working Group September 25-26, 2008 Unanimously Approved Markets and Operations Policy Committee October 14-15, 2008 Unanimously Approved Action Requested: Approve Recommendation 73 of 90

186 74 of 90 Southwest Power Pool First Revised Sheet No. 128 FERC Electric Tariff Superseding Substitute Original Sheet No. 128 Fifth Revised Volume No. 1 SCHEDULE 2 Reactive Supply and Voltage Control from Generation or Other Sources Service I. GENERAL 1. Definitions (These definitions are to be used in this Schedule 2 only; to the extent of a conflict between these definitions and other definitions in the Tariff, these definitions control in the interpretation of this Schedule 2; other capitalized terms are defined elsewhere in this Tariff) 1.1 Dead Band (DB): A contiguous range of Power Factor operation where an hourly PF is greater than or equal to 0.95 (lead or lag). 1.2 Point of Interconnection (POI): The location where the generator connects to the Transmission System Power Factor (PF): The power factor of a QG as measured or determined by the integrated hourly MW and MVAr values at its POI. 1.4 Qualified Generator (QG): A generator, or a single generator that is part of a group of generators at a single Point of Receipt, that has been recognized by the Transmission Provider as meeting the criteria specified in Section II to receive compensation under this Schedule Reactive Compensation (RC): The monthly amount as calculated in Section III.B. 1.6 Reactive Compensation Rate (RCR): The amount per MVArh specified in Section III.A. 1.7 Reactive Power Inside Deadband (RPID): As defined in Section III.B Reactive Power Outside Deadband (RPOD): As calculated in Section III.B.2. Issued by: L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: October 11, 2007 Effective: October 11, 2007 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. RM and RM , issued February 16, 2007, Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, III FERC Stats. & Regs., Regs. Preambles 31,241 (2007). 74 of 90

187 75 of 90 Southwest Power Pool First Revised Sheet No. 129 FERC Electric Tariff Superseding Substitute Original Sheet No. 129 Fifth Revised Volume No Through and Out Reactive Revenue (T&O Reactive Revenue): The amount of reactive power revenue allocated to a Zone each monthly year that was collected by the Transmission Provider from Through and Out transactions Zonal Reactive Compensation (ZRC): The monthly sum of the RC for all QGs in the pricing zone Zonal PeakAverage Demand: The Zone s monthly transmission peaks Zone: SPP pricing zone as defined in the SPP OATT. 2. Purpose In order to maintain Transmission System voltages within acceptable limits, generation facilities and non-generation resources capable of providing this service that are connected to the Transmission System are operated to produce (or absorb) reactive power. Reactive Supply and Voltage Control from Generation or Other Sources Service (Reactive Supply) must be provided to support each transaction on the Transmission System. The amount of Reactive Supply required in real time to maintain Transmission System voltages within limits that are generally accepted in the region and consistently adhered to by the Transmission Provider will vary with conditions on the Transmission System. Generators operating within a range of 0.95 leading to 0.95 lagging PF will not receive compensation for supplying such reactive power. Generators meeting the requirements of this Schedule 2 will be compensated for producing reactive Issued by: L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: October 11, 2007 Effective: October 11, 2007 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. RM and RM , issued February 16, 2007, Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, III FERC Stats. & Regs., Regs. Preambles 31,241 (2007). 75 of 90

188 76 of 90 Southwest Power Pool First Revised Sheet No. 130 FERC Electric Tariff Superseding Second Substitute Original Sheet No. 130 Fifth Revised Volume No. 1 power outside the DB when such operation is at the direction of the Transmission Provider or local Balancing Authority. This Schedule 2 provides the criteria specifying which generators qualify to receive compensation for reactive power and sets out the rates and charges necessary to comparably compensate all QGs for such operation. II. QUALIFIED GENERATOR REQUIREMENTS A. General: All existing generation owners eligible to collect charges for Reactive Supply for generators connected to the Transmission System under a cost-based rate schedule on file with the Commission as of October 1, 2006, as well as nonjurisdictional generation owners operating generating facilities that are being compensated for the provision of reactive supply and voltage control services to SPP as of October 1, 2006, are deemed to have met the technical requirements of Section II.B and therefore are QGs. Initially, in order to receive compensation under this Schedule 2, all other owners of generation must apply to the Transmission Provider for QG status and provide the necessary operating data set forth in Addendum 1 to this Schedule 2 to the Transmission Provider no later than 30 days following the final approval of this Schedule 2 by the Commission. Subsequently, owners of other generation must apply to the Transmission Provider for QG status and provide the necessary operating data to the Transmission Provider. The Transmission Provider shall recognize new QGs throughout the year if the generator meets the requirements set out in Section II.B. A new QG will be eligible for compensation at the beginning of the first month after SPP acceptance of the generation owner s application. To the extent the operating data requested in Addendum 1 has been previously provided to SPP pursuant to a generation interconnection agreement or through input for SPP transmission operational or planning models, that operating data shall not be Issued by: L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: April 8, 2008 Effective: June 7, of 90

189 77 of 90 Southwest Power Pool FERC Electric Tariff Fifth Revised Volume No. 1 First Revised Sheet No. 130A Superseding Original Sheet No. 130A required with the application. Once the QG provides the necessary operating data to SPP, it shall be eligible to receive compensation under this Schedule 2 as provided in Section III. The QG s RC will be included under this Schedule 2 in the first full billing month after the required information is received. The Transmission Provider shall have the right to remove the QG status of any generation resource that fails to meet any requirements of Section II.B. B. Technical: 1. Each QG shall designate the entity that is to receive dispatch instructions and the entity to receive compensation. 2. The generation resource must be able to produce reactive power outside the Dead Band at its Point of Interconnection with the Transmission System. Issued by: L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: April 8, 2008 Effective: June 7, of 90

190 78 of 90 Southwest Power Pool Substitute Original Sheet No. 131 FERC Electric Tariff Superseding Original Sheet No. 131 Fifth Revised Volume No Each QG shall maintain the capability to provide MWh, MVArh and voltage data, by such means of transmittal, at such intervals and at such accuracy level as SPP shall require. 4. The generation resource must be able to follow a voltage schedule and respond to dispatch instructions from the Transmission Provider and/or the local Balancing Authority. III. RATES, CHARGES, AND REVENUE DISTRIBUTION The following sets forth the rates, charges and revenue distribution pursuant to this Schedule 2. All QGs shall be treated the same. Issued by: L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: July 16, 2007 Effective: March 1, 2007 Filed to comply with order of the Federal Energy Regulatory Commission, Docket No. ER and -001, issued May 25, 2007, 119 FERC 61,199 (2007). 78 of 90

191 79 of 90 Southwest Power Pool Substitute Original Sheet No. 132 FERC Electric Tariff Superseding Original Sheet No. 132 Fifth Revised Volume No. 1 A. Reactive Compensation Rate The RCR shall be based on the cost of reactive power production from recently constructed generators so as to reflect the upper end of such costs. The RCR shall be $2.26 per MVArh. The Transmission Provider may periodically review the RCR to determine whether it remains at or near the upper end of a reasonable range of cost of producing reactive power by generators recently connected to the Transmission System. B. Qualified Generator Compensation The compensation paid to QGs each month will be based on the calculations as set forth below. 1. Determine the integrated hourly values for real and reactive power generated by each Qualifying Generator for each month. 2. Calculate the Reactive Power Outside the Dead Band (RPOD). For each hour of each month, calculate the amount of Reactive Power inside the Dead Band (in MVArh) that the QG would have had to produce or absorb to maintain a PF of 0.95 at its actual real power output level (RPID). Then subtract the absolute value of the RPID from the absolute value of the actual reactive power output from the QG for that hour (in MVArh). If the absolute value of RPID is greater than the absolute value of the actual reactive power output of the QG, then the RPOD for that hour is zero. The monthly RPOD is the sum of the hourly RPOD calculations for each QG for each month. 3. Calculate the total compensation that the owner of each QG will receive for each month (RC) by multiplying the QG s monthly RPOD, times the RCR. RCmonthly = RCR * RPOD monthly Issued by: L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: July 16, 2007 Effective: March 1, 2007 Filed to comply with order of the Federal Energy Regulatory Commission, Docket No. ER and -001, issued May 25, 2007, 119 FERC 61,199 (2007). 79 of 90

192 80 of 90 Southwest Power Pool Substitute Original Sheet No. 133 FERC Electric Tariff Superseding Original Sheet No. 133 Fifth Revised Volume No. 1 C. Calculation of Rates The rates paid by Transmission Customers will be based on the calculations set forth below. All of the amounts calculated below shall be actuals for each month with no true-ups. 1. Calculate the amount of T&O Reactive Revenue allocated to each Zone by taking the total amount of revenue generated by this Schedule 2 from Through and Out transactions for each month and allocate it on a pro-rata share based on the ZRC for the same month.. 2. Calculate the total amount of revenue to be collected for each month by zone, by summing the RC for each QG by zone less the T&O Reactive Revenue. ZRC = Σn=1 to x(rc) T&O Reactive Revenue; where: x=total number of QGs in the Zone 3. Calculate the Schedule 2 Rates, for each Zone, as shown below. a. Monthly Rate ($/MW/Mo) = ZRC / Zonal Peak Demand b. Weekly Rate ($/MW/Wk) = Monthly Rate times 12 / 52 c. Daily Off-Peak Rate ($/MW/Day) = Weekly Rate / 7 d. Daily On-Peak Rate ($/MW/Day) = Weekly Rate / 5 e. Hourly Off-Peak Rate ($/MW/Hr) = Daily Off-Peak Rate / 24 f. Hourly On-Peak Rate ($/MW/Hr) = Daily On-Peak Rate / 16 Issued by: L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: July 16, 2007 Effective: March 1, 2007 Filed to comply with order of the Federal Energy Regulatory Commission, Docket No. ER and -001, issued May 25, 2007, 119 FERC 61,199 (2007). 80 of 90

193 81 of 90 Southwest Power Pool Substitute Original Sheet No. 134 FERC Electric Tariff Superseding Original Sheet No. 134 Fifth Revised Volume No. 1 The total charge in any day, pursuant to an hourly service reservation, shall not exceed the applicable rate for daily service specified above for the applicable Zone, times the highest amount of hourly service reserved in any hour during such day. In addition, the total charge in any week pursuant to a reservation for hourly or daily service shall not exceed the rate for weekly service specified above for the applicable Zone, times the highest amount of hourly or daily service reserved in any hour or day during such week. On-Peak and Off Peak Off-Peak days shall be Saturdays and Sundays and all NERC holidays. All other days shall be On-Peak. All hours during Off-Peak days shall be Off-Peak. On-Peak hours during On-Peak days shall be all hours from HE 0700 through HE 2200 Central Prevailing Time. All other hours during On-Peak days shall be Off-Peak. 4. For the purposes of determining the charge applicable to transactions under this Tariff, the transaction will be charged based on the applicable zonal rate where the load is physically located. 5. If the service is a Through and Out transaction, the transaction will be charged based on the simple average of all zonal rates for the applicable period of service. 6. The data used in the calculations under this Section III. C. shall be from the same month as the monthly RPOD used to calculate the RC in Section III. B. D. Collection of Charges and Distribution of Revenues 1. All load shall pay the Transmission Provider a charge for Reactive Supply determined by multiplying the applicable rate as calculated in Section III.CB by the Reserved Capacity for the Transmission Customer taking Issued by: L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: July 16, 2007 Effective: March 1, 2007 Filed to comply with order of the Federal Energy Regulatory Commission, Docket No. ER and -001, issued May 25, 2007, 119 FERC 61,199 (2007). 81 of 90

194 82 of 90 Southwest Power Pool Substitute Original Sheet No. 135 FERC Electric Tariff Superseding Original Sheet No. 135 Fifth Revised Volume No. 1 Point-To-Point Transmission Service during that month or the Network Customer s and non-rate terms and conditions customer s average coincident peak during the month. The billing units used herein will be for the same month as the month used to determine the RPOD. After it has sufficient data to calculate the monthly RPOD, SPP shall bill customers for monthly charges under this Schedule 2 in the next billing cycle. SPP also will post the applicable monthly Schedule 2 charges promptly after it possesses the data necessary to calculate such charges. 2. In the event that the monthly revenue collected for a zone does not match the ZRC in a month, the revenues distributed that month to each QG in the affected zone shall be based upon its RC for that month divided by the applicable ZRC for that month multiplied by total zonal revenues collected pursuant to this Schedule 2 for that month. E. Joint Owned Units The Transmission Provider will compensate the entity designated in II.B.1 for a jointly owned QG. The Transmission Provider is not responsible for disbursing revenue to other owners. F. Multiple Generators Behind a Common Meter If more than one generator exists behind a single meter, the Transmission Provider must individually certify all the generators behind the meter as QGs. Compensation will be handled in the same way as an owner with multiple units in the same zone. Issued by: L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: July 16, 2007 Effective: March 1, 2007 Filed to comply with order of the Federal Energy Regulatory Commission, Docket No. ER and -001, issued May 25, 2007, 119 FERC 61,199 (2007). 82 of 90

195 83 of 90 Southwest Power Pool FERC Electric Tariff Fifth Revised Volume No. 1 Original Sheet No. 135A IV. QUALIFIED GENERATOR STATUS A. Re-Evaluation of Qualified Generator Status 1. If a QG fails to comply with the Transmission Provider s or Balancing Authority s voltage control requirements three or more times in a calendar month, or six or more times in the preceding twelve month period, for reasons other than planned or unscheduled outages, the Transmission Provider shall determine whether the Generation Resource should continue to be a QG based on the criteria established in Section II.B of this Schedule In making a determination of whether a Generation Resource should continue to be a QG, the Transmission Provider will evaluate, among other factors, whether the Generation Resource was operated consistently with its design characteristics, if the QG responded in accordance with other agreements and whether system conditions prevented it from responding as required by the Balancing Authority or Transmission Provider. Issued by: L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: July 16, 2007 Effective: March 1, 2007 Filed to comply with order of the Federal Energy Regulatory Commission, Docket No. ER and -001, issued May 25, 2007, 119 FERC 61,199 (2007). 83 of 90

196 84 of 90 Southwest Power Pool Second Substitute Original Sheet No. 136 FERC Electric Tariff Superseding Substitute Original Sheet No. 136 Fifth Revised Volume No If the Transmission Provider determines that the generator should not continue to be a QG, the Transmission Provider shall notify the owner and stop providing reactive compensation to such generator owner. B. Regaining Qualified Generator status: If a generator has had its status as a QG removed by the Transmission Provider, such generator may be reinstated to receive reactive compensation six (6) billing months after disqualification. If the owner of the generator desires to be reinstated, it must make application for such reinstatement to the Transmission Provider and demonstrate that the cause(s) for the disqualification has been remedied. The Transmission Provider shall waive the six month period and immediately reinstate the QG status if it determines that such status was erroneously removed. V. QUALIFIED GENERATOR DISPATCH CRITERIA All QGs will be required to maintain reactive supply pursuant to a voltage schedule provided by SPP or the applicable Balancing Authority. SPP and the applicable Balancing Authority shall issue voltage schedules to all QGs on a nondiscriminatory basis. In the event of a system contingency or emergency situation that requires specific attention to reactive production, SPP or the applicable Balancing Authority will determine, based on real-time data and engineering studies of current and prospective conditions, the most effective solution to maintain transmission system reliability. For a circumstance that requires specific attention to reactive production, SPP or the applicable Balancing Authority will perform an engineering study to determine the most effective operational plan. SPP or the applicable Balancing Authority will issue reactive dispatch instructions or revised voltage schedules on a non-discriminatory basis based upon generator availability, location, and reactive capability, for such purpose. Issued by: L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: December 20, 2007 Effective: March 1, 2007 Filed to comply with order of the Federal Energy Regulatory Commission, Docket No. ER and -003, issued November 20, 2007, 121 FERC 61,196 (2007). 84 of 90

197 85 of 90 Southwest Power Pool Substitute Original Sheet No. 136 FERC Electric Tariff Superseding Original Sheet No. 136 Fifth Revised Volume No. 1 ADDENDUM 1 TO SCHEDULE 2 Operating Data to be Provided by Generator Operators Seeking QG Status The following is the list of necessary operating data to be provided as part of an application to become a QG. Issued by: 1. Nameplate data, certified factory test reports, and reactive capability curves for the generator. 2. Real and reactive power loads at maximum generator output for station service load served from the generator leads before delivery into the transmission system. 3. Nameplate data and copies of certified factory test reports for the generator step-up transformer. For transformers having tapped windings, identify the tap connections at which the transformer is operated. 4. One line schematics showing the connection of the generator to the SPP Transmission System, location of service to station service loads, and the location of metering and telemetry points. 5. Identification of the interconnection agreement governing the connection of the generator to the transmission system and citation to those provisions in the agreement that govern the production of reactive power and voltage regulation. 6. Self assessment (or certification) by generator owner of the ability of the generator to provide deliveries of real and reactive power to the SPP Transmission System, net of all loads served prior to the connection with the SPP Transmission System, with a power factor outside the +/- 95% deadband, to receive and follow reactive power dispatch instructions, and to regulate the voltage at a the point of interconnection with transmission system pursuant to a voltage schedule. 7. A copy of the most recent tests of the generator, the generator s protection system, the generator s control system and the generator s excitation system as performed in accord with the SPP Criteria. L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: July 16, 2007 Effective: March 1, 2007 Filed to comply with order of the Federal Energy Regulatory Commission, Docket No. ER and -001, issued May 25, 2007, 119 FERC 61,199 (2007). 85 of 90

198 86 of 90 Southwest Power Pool Substitute Original Sheet No. 136 FERC Electric Tariff Superseding Original Sheet No. 136 Fifth Revised Volume No. 1 Issued by: L. Patrick Bourne, Director Transmission and Regulatory Policy Issued on: July 16, 2007 Effective: March 1, 2007 Filed to comply with order of the Federal Energy Regulatory Commission, Docket No. ER and -001, issued May 25, 2007, 119 FERC 61,199 (2007). 86 of 90

199 87 of 90 Southwest Power Pool, Inc. MARKETS AND OPERATIONS POLICY COMMITTEE Recommendation to the Board of Directors on Attachment J Waiver Requests Westar Waiver October 28, 2008 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 September 15, 2008, 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 Westar Energy for new Designated Resources for 99 MW from the Central Plains wind farm located in Wichita, Kansas, based on the upgrade costs associated with transmission from this resource. SPP s 120 day deadline under Attachment J is January 13, Analysis: Westar Energy requested a waiver based upon Section III.C 2. ii & iv of Attachment J for reconsideration on the basis that the request is a 10 year reservation and a wind resource. This waiver request has been discussed in the regular September, meeting of the Cost Allocation Working Group (CAWG). A special teleconference was held on October. 9, Based on the discussion and action of the CAWG during the special meeting, the CAWG is recommending that the SPP Regional State Committee (RSC) recommend to the Board of Directors to approve to increase the funding of the waiver in accordance with the RSC approved new policy for the direct assignment portion for the wind resources. This would approve 67% of the upgrade cost to be regionally funded. This would leave 33% to be directly assigned to Westar Energy, up to a cap of $2,805,000. Recommendation The recommendation of the MOPC is to provide an additional Base Plan funding of $38,981 based on the 10 year reservation and existing tariff provisions. The MOPC acknowledges that a policy revision that has been approved by the CAWG/RSC; that is ultimately approved through the SPP/FERC process would alter the resulting recommendation. Approved: Markets and Operations Policy Committee October 14-15, 2008 Approved with No Opposition; 1 Abstention (Empire) Action Requested: Approve Recommendation 87 of 90

200 88 of 90 Southwest Power Pool, Inc. MARKETS AND OPERATIONS POLICY COMMITTEE Recommendation to the Board of Directors on Attachment J Waiver Requests City of Coffeyville, KS Waiver October 28, 2008 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 September 11, 2008, 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 the city of Coffeyville (CMLP) for new Designated Resources for a profiled reservation request of 16 MW beginning in 2008 and growing to 197 MW in 2042 for the city, based on the upgrade costs associated with transmission from this resource. SPP s 120 day deadline under Attachment J is January 9, Analysis: CMLP requested a waiver based upon Section III.C 2. ii of Attachment J for reconsideration based on that the request is a 34 year reservation.. This waiver request has been discussed in the regular September, meeting of the Cost Allocation Working Group (CAWG). A special teleconference was held on October. 9, Based on the discussion and action of the CAWG during the special meeting, the CAWG is recommending that the SPP Regional State Committee (RSC) recommend to the Board of Directors to approve to fully fund the waiver for the SPP jurisdictional upgrades. This will specifically exclude the required upgrades that are owned by the city of Coffeyville. Recommendation The recommendation of the MOPC to the Board of Directors to approve the waiver request to fully fund the projects excluding the CMLP-owned direct assignment upgrades, based on the 34 year reservation and realizing anticipated Safe Harbor limit using 91 MW, would allow fully funding the project with the exclusion of the CMLP-owned direct assignment upgrades. Approved: Markets and Operations Policy Committee October 14-15, 2008 Unanimously Approved Action Requested: Approve Recommendation 88 of 90

201 89 of 90 Organizational Roster SPP Staff Southwest Power Pool, Inc. MARKETS AND OPERATIONS POLICY COMMITTEE Recommendation to the Board of Directors October 28, 2008 Westar-Sunflower, Clay Center-Greenleaf Project Cancellation Knob Hill Steele City & Kelly S. Seneca Project Approval Background In September 2007, Westar asked SPP staff to examine alternatives to the proposed Clay Center Greenleaf project in the STEP in anticipation of a new pipeline known as the TransCanada Pipeline coming into the area. However, without the pipeline load in the STEP models, staff stated additional study of the area would be completed in the 2008 STEP regional reliability effort. In January 2008, the SPP Board of Directors (BOD) approved the Clay Center Greenleaf project as a regional reliability upgrade needed in summer 2008, and following, NTCs were sent to Sunflower and Westar on this project. As anticipated, the new TransCanada Pipeline load points created an immediate reliability assessment need. SPP staff decided to study the area out of cycle from the STEP reliability assessment process to determine the best regional solution as soon as possible. Analysis SPP performed a study on the addition of the TransCanada Pipeline loads to determine which project, of several proposed alternatives, would provide the best regional solution. See the study report for more details. [MOPC Item - Knob Hill - S Beatrice & Clay Center Junction - Greenleaf Alternatives - Transmission Line Study - Final Report.doc]. The results conclude that the Clay Center-Greenleaf project no longer provides an adequate regional reliability solution. The report goes on to conclude that the best solution is to build a new 115 kv line from Knob Hill to Steele City and re-conductor the Kelly- South Seneca 115 kv line, and it is therefore the recommended alternative. Clay Center Greenleaf has an RTO determined need date of summer Knob Hill Steele City and Kelly Seneca projects are expected to be in service by summer The TWG recognizes that there is a two year window which will require a reliability mitigation plan. Sunflower has filed a mitigation plan which will cover the two year window. Recommendation The MOPC recommends for Board of Directors approval, the cancellation of the Clay Center (Westar) Greenleaf (MKEC) project as an SPP regional reliability project and the cancellation of the associated NTCs. The MOPC recommends for Board of Directors approval, the inclusion of the Knob Hill (Westar) Steele City (NPPD) and the Kelly South Seneca (Westar) projects, which will replace the Clay Center Greenleaf project, as needed for SPP regional reliability in the current approved STEP. Recent Approvals: TWG approved the staff recommendation unanimously, Markets and Operations Policy Committee October 14-15, 2008 Approved recommendation with 1 Opposition (ITC Great Plains); No Abstention Action Requested: Approve Recommendation. 89 of 90

202 90 of of 90

203 SPP Finance Committee Roster Harry Skilton, Chair Larry Altenbaumer, Vice Chair Gary Voigt Trudy Harper Dave Sartin Kelly Harrison Director Director AECC Tenaska AEP Westar 2

204 SPP Finance Committee Recent Activities: Amendment to SPP Credit Policy 1. Eliminated requirement for attorney opinion letter for guaranty agreements 2. RTWG & MOPC endorsed tariff language Insurance 1. Directed review of liability insurance to identify potential gaps in coverage 2. Review of policy protection against claims made against service contracts (i.e. Entergy, LG&E) Aircraft 1. Reviewing risk to determine appropriate level of insurance protection Budget 4

205 Significant Assumptions OPPD, NPPD, and LES load served under SPP tariff beginning 2Q 09 Load growth of 2.4% based on 2008 EIA 411 report Staff vacancy factor of 7% Consolidation of balancing authority complete in 2009 Construction of operating facility begins in 2009 New borrowings of $62.7 million 5 Budget Summary (millions of dollars except administrative fee) Operating Expense budget of $114.3 Headcount increase from 345 in 2008 budget to 417 Capital Expenditure budget of $29.6 requiring term loan acquisitions of $62.7 in 2009 Administrative Fee of

206 Capital Expenditures (millions of dollars) Project Total Balancing Authority Consolidated $1.3 $0.1 $0.0 $1.4 Future Market Development Business Information: Mgmt & Delivery Facility Development Other Foundation Projects Total $29.6 $47.4 $25.2 $ Expense Analysis (millions of dollars except headcount) 2009 Budget 2008 Budget 2008 Forecast Salary & Benefits $48.7 $44.0 $40.8 Assessments and Fees Outside Services Depreciation & Amortization Other Expense Total $114.3 $101.4 $93.3 Headcount

207 Growth in SPP Staff 60, , Dollars (thousands) 40,000 30,000 20, Year-end headcount 10, Salary & Benefit Expense Number of Employees 9 Revenue Analysis (millions of dollars) 2009 Budget 2008 Budget 2008 Forecast Tariff Administration Service $56.6 $59.6 $56.5 Fees and Assessments Contract Services Revenue Study Revenue Other Income Total $101.6 $93.0 $

208 SPP Tariff Administration Fee $0.230 $0.210 $0.190 Budget NRR / Budget Load $0.170 $0.150 $0.130 Actual / Budget Admin Fee Proposed Board Resolutions Approve the 2009 SPP operating and capital budgets as submitted. Establish an assessment rate and tariff administrative fee rate (schedule 1A) of 17 /MWh effective January 1,

209 Southwest Power Pool, Inc. FINANCE COMMITTEE Recommendation to the Board of Directors October 28, Operating and Capital Budgets Organizational Roster The following persons are members of the Finance Committee: Harry Skilton, Chair Larry Altenbaumer Trudy Harper Kelly Harrison David Sartin Gary Voigt SPP Director SPP Director Tenaska Westar AEP Arkansas Electric Background Section 6.5 of the SPP Bylaws identifies establishment of annual and long-term budgets as a primary duty of the Finance Committee. Analysis The Finance Committee met on September 19, 2008 to review SPP s proposed budget for SPP s 2009 proposed budget includes expenditures as follows: $000 Operating Expense (incl. dep. & am.) $115,003 Debt Repayment $8,206 FERC Assessments $11,103 Capital Expenditures $29,637 SPP s 2009 budget has also been segregated to identify costs associated with on-going operations separately from costs associated with new or developing initiatives or specific services. Service or Initiative Revenue Expense Capital Regional Entity $7,124 $6,481 $0 Facility Mgmt ,676 Bus. Information: Mgmt & Delivery 0 1,470 1,900 Balancing Authority Consolidation ,410 Future Markets 0 0 1,891 Recommendation The Finance Committee recommends the SPP Board of Directors approve the 2009 SPP operating and capital budgets as submitted. Approved: Finance Committee September 19, 2008 Action Requested: Approve Recommendation 1 of 32

210 SPP 2009 BUDGET AS PRESENTED TO THE SPP BOARD OF DIRECTORS FRIDAY, OCTOBER 3, 2008 SECTION 1 INTRODUCTION AND OVERVIEW A. Budget Introduction B. SPP 2009 Administrative Rate Overview C. Net Revenue Requirement Growth 2 SPP PROJECT DESCRIPTION AND ANALYSIS A. Overview B. Balancing Authority Consolidation C. Future Market Development D. Business Information: Management & Delivery Strategy E. Facility Management F. Regional Entity G. SPP 2009 Incremental Activity List BUDGET DETAIL AND COMMENTARY A. Income Statement Commentary B. Reconciliation of Budget Submissions C. Summary Balance Sheet 4 SUPPLEMENTAL ANALYSIS A. Administrative Fee History B. Headcount Analysis C. Three Year Income Statement Forecast D. Three Year Cash Flow Forecast E. Administrative Fee Sensitivity 2 of 32 1

211 SOUTHWEST POWER POOL 2009 BUDGET INTRODUCTION AND ADMINISTRATIVE FEE OVERVIEW ALL DOLLAR AMOUNTS ARE IN THOUSANDS (000 S) EXCEPT FOR RATES INTRODUCTION: Southwest Power Pool (SPP) is continuing to navigate through a significant growth period as it provides the services of a Regional Transmission Organization (RTO) and a Regional Entity (RE). Additionally, SPP staff and management are maturing as an organization in both its ability to make accurate assumptions regarding required resources and to employ those resources for the benefit of the members and customers. As a result of this growth and maturation process, SPP has designed the annual budget process using a zero-based budget approach as in previous years and incorporated additional layers of collaborative planning The zero-based budget method requires all expenditures be justified, as opposed to only explaining amounts requested in variance of the previous period's funding. SPP management facilitated a series of strategic planning and budget meetings to review all existing business functions, new activities and new projects. These collaborative strategic planning sessions commenced with a half day discussion on May 19 th led by Carl Monroe in which all existing business functions were identified, justified, and categorized by SPP s management team. Additionally, over a hundred potential and required future activities and functions were identified during a brainstorming session. These were grouped and categorized into 82 initiatives and during numerous further independent and group meeting sessions, each incremental activity for 2009 through 2011 was substantiated with a written justification consisting of a project description and owner, cost/benefit analysis, project dependencies and other related information. This exercise also included discussion of projects underway in 2008 not likely to be completed until As the budget timeline proceeded, all projects were vetted in an open forum by SPP management and ranked using the following categories: 1) required by regulatory orders, 2) required by members or Board of Directors, 3) projects where benefits to SPP outweigh costs and 4) projects not needed by SPP, which were subsequently dropped from the list. During this same timeframe of project reviews, SPP management conducted a series of budget meetings in which operating expenses and revenues for 2009 were itemized and reviewed. Each line item in the budget was discussed by all SPP management and justified to the SPP senior management. Such collaboration ensures all pertinent facts are shared and vetted by the management group, allowing for well-informed decisions to be made and resource utilization to be maximized. 3 of 32 2

212 SOUTHWEST POWER POOL 2009 BUDGET INTRODUCTION AND ADMINISTRATIVE FEE OVERVIEW SPP ADMINISTRATIVE FEE CALCULATION: SPP s projected 2009 net revenue requirement ( NRR ) is $56,478, as compared to 2008 budget NRR of $61,462. The primary drivers of the NRR decrease include a reduction in debt service of $4,000 and additional revenues generated through contract services and engineering studies of $7,496. These reductions are partially offset by increases in staffing expense of $4,610 and outside services, maintenance and administrative expense of $2,698. SPP s capital budget for 2009 is $29,637 as compared to 2007 and 2008 approved capital spending of $19,165 and $23,859, respectively. Based upon the projected NRR of $56,478 and projected billing determinants of 331,360 MW/h SPP s 2008 administrative fee is recommended to decrease to 17 per MWh from 19 per MWh used in 2007 and Calculation of the administrative fee is as follows: 2009 BUDGET 2008 RUN RATE 2008 BUDGET Gross Revenue Requirement $101,750 $88,279 $95,050 Less: NERC Reimbursement (7,124) (3,935) (4,609) Schedule 12 Revenue (FERC Fee) (11,103) (7,556) (9,000) Contract Services Revenue (21,538) (18,526) (17,153) Other Revenues (5,506) (4,383) (2,826) Net Revenue Requirement $56,478 $53,879 $61,462 Divided by Estimated Billing Determinants / MWh* 331, , ,497 Calculated Administrative Fee / MWh $0.170 $0.182 $0.197 Recommended Admin Fee / MWh $0.170 $0.190 $0.190 * 2008 Estimated Billing Determinants are defined as coincident peak for network service and capacity for point to point service in MWh 4 of 32 3

213 SOUTHWEST POWER POOL 2009 BUDGET INTRODUCTION AND ADMINISTRATIVE FEE OVERVIEW Revenue and expense items used to calculate NRR will be outlined in subsequent pages. Billing determinants were forecasted using actual trailing 12 month billing units (July 2007 June 2008) plus an EIA-411 growth calculation of 2.4%. The EIA-411 is an annual report to the Department of Energy s Office of Energy Emergency Operations and is used to forecast energy demand and capacity over a 10 year span. In addition, billing determinants for the Nebraska transmission owners were included in SPP s billing determinants beginning in second quarter 2009 representing 9.7% of total billing units. 5 of 32 4

214 SOUTHWEST POWER POOL NET REVENUE REQUIREMENT GROWTH (000's) 2009 Budget 2008 Budget 2008 Forecast Fav/ (Unfav) Variance Compared to: Budget % Forecast % Variance Explanation Tariff Administration Service 56,601 59,644 56,536 (3,043) -5% 66 0% Fees and Assessments 18,227 13,609 11,491 4,618 10% 6,736 59% Increases in both NERC and FERC (Sched.12) Fees Contract Services Revenue 21,538 17,153 18,526 4,385 26% 3,012 16% Additional revenue associated with FERC Order 890 compliance Study Revenue 4,911 1,800 3,359 3, % 1,553 46% Increase in revenue associated with resource rate increase Other Income (430) -57% (428) -57% Total Revenue 101,602 92,961 90,664 8,641 9% 10,938 12% Salary & Benefits 48,659 44,049 40,757 (4,610) -10% (7,902) -19% Increase primarily driven by additional staff in 2009 Employee Travel 1,504 1,268 1,417 (236) -19% (87) -6% Administrative 2,821 1,789 2,354 (1,032) -58% (467) -20% Increase associated with add'l property taxes and general office exp Assessments and Fees 11,103 9,000 7,551 (2,103) -23% (3,552) -47% Increase in FERC (Sched.12) Fees not applicable in NRR Meetings (125) -24% (88) -16% Communications 2,805 2,813 2, % (624) -29% Maintenance 4,893 4,255 4,332 (638) -15% (561) -13% Increase associated with additional systems and hardware maint Leases 1,090 1, (84) -8% (107) -11% Outside Services 16,552 15,524 13,548 (1,028) -7% (3,004) -22% Increase primarily due to Engineering, Contract Svcs & Regulatory Regional State Committee % 58 8% Depreciation & Amortization 20,709 18,540 17,212 (2,169) -12% (3,497) -20% Additional assets being depreciated; not applicable in NRR Interest Expense 3,524 2,919 2,579 (605) (945) -37% Assumes additional interest on a new debt issuance in 2009 Interest Income (750) (1,000) (942) (250) 25% (192) 20% Total Expenses 114, ,384 93,285 (12,869) -13% (20,968) -22% Net Income (12,651) (8,423) (2,620) (4,228) -50% (10,031) 383% Debt Repayment 8,206 12,206 12,206 4,000 4,000 Assumes new debt does not require principal payments in 2009 MW/h Forecast 331, , ,135 18,864 35,225 Increase primarily due to Nebraska integration Net Revenue Requirement 56,478 61,462 53,879 4,983 (2,599) Calculated Admin Fee / MWh $0.170 $0.197 $0.182 $0.026 $0.011 Recommended Admin Fee / MWh $0.170 $0.190 $0.190 $0.020 $0.020 Capital Expense 29,637 23,859 Headcount of 32 5

215 SPP 2009 BUDGET SPP PROJECT DESCRIPTION AND ANALYSIS Overview Balancing Authority Consolidation Future Market Development Business Information: Management & Delivery Strategy Facility Management Regional Entity SPP 2009 Incremental Activity List 7 of 32 6

216 SOUTHWEST POWER POOL 2009 BUDGET PROJECT OVERVIEW, DESCRIPTIONS & ANALYSIS SPP has identified $29,637 in capital expenditures associated with forty four specifically identified projects for While most of these projects are foundation activities, they all support SPP s strategic goals and vision. Capital expenditures include purchases of equipment, software and services to enhance functionality of SPP s services provided by transmission and market systems. In addition, $2,981 in operating expenses and twelve incremental headcount have been budgeted in 2009 in association with these projects. A breakdown of capital and operating expense is as follows: CAPITAL EXPENDITURES Hardware Software Comm Facilities Furniture Consulting Other Total 2009 $13,009 $5,023 $0 $7,181 $0 $4,425 $0 $29, $9,941 $11,748 $0 $20,000 $0 $5,679 $0 $47, $9,247 $8,668 $0 $0 $0 $7,282 $0 $25,197 Total $32,197 $25,438 $0 $27,181 $0 $17,386 $0 $102,201 Salary & Benefits OPERATING EXPENSE & HEADCOUNT Travel & Meetings Comm Facilities Consulting Maint Other Total 2009 $963 $39 $24 $0 $1,223 $694 $39 $2, $3,989 $5 $516 $1,946 $1,360 $812 $1,057 $9, $6,659 $53 $12 $1,646 $1,380 $866 $1,096 $11, Total $11,611 $97 $552 $3,592 $3,963 $2,372 $2,192 $24, Head count The following pages will describe major projects in greater detail. A full list of projects with capital and operating budget impacts appear at the end of this section. 8 of 32 7

217 SOUTHWEST POWER POOL 2009 BUDGET PROJECT OVERVIEW, DESCRIPTIONS & ANALYSIS BALANCING AUTHORITY CONSOLIDATION CAPITAL EXPENDITURES Hardware Software Comm Furniture Consulting Other Total $100 $950 $0 $0 $360 $0 $1, OPERATING EXPENSE & HEADCOUNT Salary & Travel & Head Benefits Meetings Comm Consulting Maint Other Total count $664 $0 $0 $0 $0 $0 $664 9 Consolidation of the SPP Balancing Authority (BA) is a priority initiative in SPP s Strategic Plan and is a necessary step in the move towards an Ancillary Services Market. The consolidation will allow for added benefits of area control error (ACE) diversity and market stability. SPP will operate a 24X7 desk requiring a staff of shift operators and day schedulers. This desk will be responsible for the balancing of the net actual and net scheduled interchange for the SPP footprint. SPP will rely on its existing EMS to calculate, monitor and adjust the ACE calculation. The desk will also be responsible for planning and coordinating the day to day BA operations, including emergency operating plans, checkout procedures and governmental reporting. The project is currently being further specified, planned, and scheduled by the Balancing Authority Steering Committee under the MOPC. The planning phase is expected to be completed in Fall 2008 and software development is expected to begin after approval of the Ancillary Services market in Fall Staffing will begin in early 2009 to be completed by the summer of The project is expected to be implemented in Fall of 32 8

218 SOUTHWEST POWER POOL 2009 BUDGET PROJECT OVERVIEW, DESCRIPTIONS & ANALYSIS FUTURE MARKET DEVELOPMENT CAPITAL EXPENDITURES Hardware Software Comm Furniture Consulting Other Total 2009 $0 $740 $0 $0 $1,151 $0 $1, $5,250 $10,500 $0 $0 $5,609 $0 $21, $5,500 $7,754 $0 $0 $7,212 $0 $20,466 TOTAL $10,750 $18,994 $0 $0 $13,972 $0 $43,716 Salary & Benefits OPERATING EXPENSE & HEADCOUNT Travel & Meetings Comm Consulting Maint Other Total 2009 $0 $0 $0 $0 $0 $0 $ $2,333 $0 $0 $180 $0 $110 $2, $4,951 $48 $0 $0 $0 $130 $5, TOTAL $7,284 $48 $0 $180 $0 $240 $7,752 Head count The implementation of the day-ahead and ancillary services markets aligns with SPP s Strategic Plan initiative to continue development of additional market services. These new market offerings will provide reliability and economic benefits to SPP s members and transmission customers. The project consists of first adding a day-ahead market with centralized unit commitment and transmission rights. The budget assumes that SPP will launch an ancillary services market after the completion of the cost/benefit study, consolidation of SPP s balancing authorities, and successful implementation of the day-ahead market. SPP s Cost Benefit Task Force (CBTF) has commissioned a cost/benefit analysis expected to be completed during early 4Q 08. The CBTF will report its findings and analysis to the Market Working Group that, upon completion of its own review of the findings, is expected to make a recommendation to the Markets and Operations Policy Committee detailing the structure and schedule for development of the markets. Prior to fully undertaking development activities, approval of the Regional State Committee, Strategic Planning Committee, Members Committee and Board of Directors will be sought. The project budget assumes a start time of March 2009 with delivery of the markets starting in first half of of 32 9

219 SOUTHWEST POWER POOL 2009 BUDGET PROJECT OVERVIEW, DESCRIPTIONS & ANALYSIS The CBTF is working on a project to determine the costs and benefits of these market implementations. The study will be completed in October The change cases the CBTF are working on are listed below: Change Case I Day-Ahead Market with Unit Commitment Addition only Change Case IIA/B- Day-Ahead Market with Unit Commitment and Co-optimized Ancillary Service Market (All Inclusive) FTR vs. TSRO Change Case III Ancillary Service Market Addition only Change Case IV Simplified Day-Ahead Market with Unit Commitment 11 of 32 10

220 SOUTHWEST POWER POOL 2009 BUDGET PROJECT OVERVIEW, DESCRIPTIONS & ANALYSIS BUSINESS INFORMATION: MANAGEMENT AND DELIVERY STRATEGY CAPITAL EXPENDITURES Hardware Software Comm Furniture Consulting Other Total $300 $40 $0 $0 $1,560 $0 $1, OPERATING EXPENSE & HEADCOUNT Travel & Meetings Comm Consulting Maintenance Other Total $0 $0 $0 $0 $1,470 $0 $1,470 0 Salary & Benefits Head count The Business Information: Management and Delivery Strategy (BIMDS), formerly the Data Warehouse project, has been renamed to more accurately reflect key purposes for the project. This project will provide a consolidated and cohesive toolset allowing data record addition and also enhanced year-over-year analysis, what-if analysis and other ad-hoc reporting. Expected benefits include: Reduced risk of manipulation of the EIS market through more robust and timely market monitoring Ability to monitor reliability and economic impact of new and existing market participants Reduced risk of penalties and fines Staff savings in both the market monitoring and data services groups Development of additional standardized information views and report layouts In the 2008 budget, $4,050 was allocated to the project which included $2,280 for hardware; $690 for software; and $1,080 for consultants. Initial steps completed in 2008 included 1) gathered data and analysis requirements, 2) defined system and architecture, 3) evaluated tools and define data strategy, and 4) defined implementation roadmap and project plan. Through the process of gathering requirements, numerous issues were identified including: Existing Decision Support System (DSS) approaching end of life with sizing and architecture insufficient to support future BIMDS requirements and volume Inefficiency of decentralized data and complexity of use No current end user reporting solution supporting non-technical report writing DSS data architecture not optimized for analysis 12 of 32 11

221 SOUTHWEST POWER POOL 2009 BUDGET PROJECT OVERVIEW, DESCRIPTIONS & ANALYSIS Initial data integration efforts are focused around the requirements of SPP s market monitoring department and contract services group. The 2009 budget was developed to complete the design and implementation effort for the market monitoring group, utilizing experienced consultants. This project will focus on the design, process and transformation of data being loaded into the data warehouse that is currently on the DSS. The Business Intelligence (BI) tool will be utilized to produce the reports, ad-hoc queries and dashboards. Initial training will be provided to the market monitoring group on use of the BI tool. The market monitoring department expects three fewer future FTEs are needed with the BIMD project in full production and the data services staff expects two fewer future FTEs upon successful implementation. The funding of this project in 2009 will accelerate the addition of market data into the data warehouse and provide a faster return on investment than if SPP relies only on internal staff. Current staff will be used to maintain the processes after development is complete. 13 of 32 12

222 SOUTHWEST POWER POOL 2009 BUDGET PROJECT OVERVIEW, DESCRIPTIONS & ANALYSIS FACILITY MANAGEMENT CAPITAL EXPENDITURES Hardware Land Building Consulting Interest Total 2009 $5,000 $775 $6,170 $495 $236 $12, $20,000 $20, $0 Total $5,000 $775 $26,170 $495 $236 $32, OPERATING EXPENSE & HEADCOUNT Salary & Benefits Travel & Meetings Operating Expense Other Total Interest 2009 $ $1,946 $946 $2, $1,646 $965 $2,611 Total $0 $0 $3,592 $1,911 $0 $5,503 SPP recently commissioned a study of its facility needs through 2018, engaging the Grogan Associates of Davidson, N.C. to perform the study and analysis. SPP s historical approach to facility management focused on reacting to near- term needs without an overarching plan to address future needs. SPP used a longer-term approach in 2005 as it began planning for the construction of a stand alone operations and data center. SPP s actual growth rate, in terms of staffing as well as services provided, has exceeded projections developed in Further exacerbating SPP s needs are a relative lack of additional office space in its current leased facility, unless SPP extends its existing lease arrangement significantly into the future. SPP currently occupies 50% of the leasable space in the office building. The results of the analysis provided two distinct options with a high level of feasibility: Option 1: Develop a new 20,000 sf data center in western Little Rock and purchase the Plaza West office building 14 of 32 13

223 SOUTHWEST POWER POOL 2009 BUDGET PROJECT OVERVIEW, DESCRIPTIONS & ANALYSIS Option 2: Develop a new 20,000 sf data center in western Little Rock on sufficient acreage to allow for the development of a 130,000 sf office building prior to the end of The near term focus is on the development of a 20,000 sf data center as it will address several significant issues, as follows: Compliance with requirements of Cyber Security plan as adopted by the NERC Board of Trustees Inadequate provision for necessary near-term expansion Disaster recovery facility inadequacies: o Public facility o Obsolete HVAC and power capabilities o Design issues, primarily location of disaster recovery facility Physical and environmental capacity exceeded by mid-2010 of primary data center 15 of 32 14

224 SOUTHWEST POWER POOL 2009 BUDGET PROJECT OVERVIEW, DESCRIPTIONS & ANALYSIS REGIONAL ENTITY OPERATING EXPENSE & HEADCOUNT RE Funding Salary & Benefits Travel & Meetings Consulting Other Total Expense Head count $7,124 $2,159 $385 $681 $3,256 $6, SPP operates as the NERC Regional Entity (RE) over an eight state area within the Eastern Interconnection. Included in SPP s annual budget submission to NERC are costs it will incur in support of delegated activities and activities that further NERC s responsibilities as the Electric Reliability Organization (ERO). These activities include: Regional Reliability Standards Program Compliance Monitoring and Enforcement Program Organization Registration and Certification Training and Education Programs Reliability Assessment and Performance Analysis Program Situation Awareness and Infrastructure Security Program All operating costs associated with performing RE functions will be recovered from NERC through its billings to SPP s registered entities on the basis of net-energy-for load. Operating costs for 2009 are estimated at $6,481 as compared to $4,609 budgeted in The funding amount exceeds operating costs due to a true-up of underfunded 2007 activities and expected underfunding of 2008 activities. The increase in operating expense is due to additional staff and support costs needed to meet the RE requirements. The budgeted staffing level of 17 FTE is not incremental to SPP s 2009 budget. The Regional Entity Trustees have approved the Regional Entity budget for Primary objectives for 2009 are: Meet the compliance audit and readiness review schedule for 2009 Develop any SPP Regional Reliability Standards to meet NERC continent-wide requirements Provide training for registered entities in the footprint to meet reliability objectives and maintain operator certifications Enhance reliability assessments and performance analysis Support NERC efforts in Situational Awareness and Infrastructure Security Provide legal, regulatory, general and administrative support for the RE 16 of 32 15

225 SOUTHWEST POWER POOL 2009 BUDGET PROJECT OVERVIEW, DESCRIPTIONS & ANALYSIS 2009 BUDGET FOR INCREMENTAL ACTIVITIES PROJECT CAPITAL AND OPERATING EXPENSES Capital Expense Operating Expense HC PROJECT TOTAL Contract Services - ICT OVEC Service Provider Renew Entergy Relationship Contract Services Docket Tracking System Museum of Discovery Exhibit Enhancements to SPP.org Corporate Affairs Future Market Development 1,891 21,359 20,466 43, Market Development Analysis 1,891 21,359 20,466 43, Lab Equipment for OIT and Outreach PM Portfolio Management Learning Management System Business Continuity Consulting Services for Market Training Process Integrity GIS & Project Tracking Solution Generation Interconnection Cluster Aggregate Study Screening Engineering Facility Management 12,676 20,000-32, Facilities 12,676 20,000-32, IT Operations Server Support Foundation 3,021 1,225 2,076 6, Hardware Refresh - Network/Telecom, Security 1, , Data Warehouse / Business Info: Mgmt & Delivery 1, , Rehost Settlements Office Hardware and Software , of 32 16

226 SOUTHWEST POWER POOL 2009 BUDGET PROJECT OVERVIEW, DESCRIPTIONS & ANALYSIS 2009 BUDGET FOR INCREMENTAL ACTIVITIES PROJECT CAPITAL AND OPERATING EXPENSES Capital Expense Operating Expense HC PROJECT TOTAL Cap-Ex Foundation - Network/Telecom, Security , Increase Generator Capacity for Maumelle Improving Customer Service Switch Gear for Maumelle Expand Datacenter Power Distribution CIP Project Replace Satellite Phones Integrated Test Environment Increase Member Circuit Bandwidth Plaza West Datacenter Expansion Expand Datacenter HVAC Capacity for Maumelle Maumelle Environmental Monitoring Enterprise Records Management System Upgrade Sonet Ring Information Technology 11,241 4,841 4,213 20, Consolidated Balancing Authority 1, , MOS Enhancements , Congestion Management Enhancements Dispatcher Training Simulator Enhancements RTOSS and RSS Enhancements MOD Reliability Stds and FERC Order Implement centralized modeling tool Reliability Recommended Improvements Seams Agreements and Coordination Activities Operations 3,135 1, , TOTAL 29,637 47,368 25, ,201 2, of 32 17

227 SPP 2009 BUDGET 2009 BUDGET DETAIL AND COMMENTARY Income Statement Commentary Reconciliation of Budget Submissions Summary Balance Sheet 19 of 32 18

228 SOUTHWEST POWER POOL 2009 BUDGET - SUMMARY INCOME STATEMENT & COMMENTARY (000's) 2009 Budget 2008 Budget 2008 Fcst 2009 Budget Variance As Compared To: 2008 Budget 2008 Fcst Fav/(Unfav) Fav/(Unfav) TOTAL REVENUE Tariff Administration Service 56,601 59,644 56,536 (3,043) -5% 66 0% Fees and Assessments 18,227 13,609 11,491 4,618 34% 6,736 59% Contract Services Revenue 21,538 17,153 18,526 4,385 26% 3,012 16% Miscellaneous Income 5,236 2,555 4,112 2, % 1,125 27% Total Revenue 101,602 92,961 90,664 8,641 9% 10,938 12% Billing Determinates 331, , ,135 18,863 6% 35,225 12% Total Revenue has increased 9% as compared to 2008 Budget and 12% as compared to 2008 Forecast. SPP classifies its revenue streams into 4 major categories: Tariff Administration Service is calculated by multiplying SPP s administrative fee by prior year coincident peak for network service and capacity for point to point service in MWh. The reduction in Tariff Administration Service is due to the decrease in SPP s administrative fee rate from 19 to 17 per MWh. Fees & Assessments consists of FERC Schedule 12 fees and NERC Regional Entity recovery. Both FERC and NERC revenue amounts are considered pass-through in which there are specific offsetting expenditures. The 2009 FERC fee is estimated at $11,103 and will be collected in 2009 and paid in The 2009 NERC recovery is $7,124 and will be collected ratably on a quarterly basis from NERC. Contract Services Revenue consists of revenues associated with the ICT and ITO contracts. The 2009 budget consists of 12 months of contractual revenue and add-on services as both projects were implemented in Miscellaneous Income includes engineering studies, member training, and other various revenues. The increase in miscellaneous revenue is primarily due to an increase in engineering study rates. Billing determinants were forecasted using actual trailing 12 month billing units (July 2007 June 2008) plus an EIA-411 growth calculation of 2.4%. In addition, billing determinants for the Nebraska transmission owners were included in SPP s billing determinants beginning in second quarter 2009 representing 9.7% of total billing units. 20 of 32 19

229 SOUTHWEST POWER POOL 2009 BUDGET - SUMMARY INCOME STATEMENT & COMMENTARY (000's) 2009 Budget 2008 Budget 2008 Fcst 2009 Budget Variance As Compared To: 2008 Budget 2008 Fcst Fav/(Unfav) Fav/(Unfav) TOTAL SALARIES, BENEFITS, TAXES & HEADCOUNT Salary & Benefits 48,659 44,049 40,757 (4,610) -10% (7,902) -19% Headcount Employee costs are the single largest component of SPP's annual operating budget comprising approximately 49% of SPP's annual gross revenue requirement for Total Salaries, Benefits and Taxes have increased 10% as compared to 2008 Budget and 19% as compared to 2008 Forecast. The 2009 Budget includes a vacancy factor of 7%. The overall increase is primarily due to the addition of 70 incremental positions as compared to the 2008 budget. A 4.8% annual salary increase is budgeted for existing employees. SPP s performance compensation plan is budgeted at approximately 15% of salaries. Cash outflows for performance compensation earned in 2009 would occur in February Funding for SPP's defined benefit retirement plan and retiree healthcare in 2009 is $3.6MM, consistent with the amounts last approved by SPP s Human Resources committee. Funding for SPP s matching contribution to the 401(k) plan is estimated at 4% of salary. Medical healthcare insurance premium rates have been budgeted to remain flat as SPP expects to benefit from its internal wellness initiatives and increased group size. Total premiums will increase in tandem with the increase in headcount. SPP currently splits healthcare premiums with employees using an 80%/20% ratio. The HR Committee reviewed SPP s benefit programs in 2008 and has not recommended changes to healthcare funding for TOTAL TRAVEL & MEETINGS Employee Travel 1,504 1,268 1,417 (236) -19% (87) -6% Meetings (125) -24% (88) -16% Total Travel & Meetings 2,148 1,787 1,973 (361) -20% (176) -9% Total Travel and Meetings have increased 20% as compared to 2008 Budget and 9% as compared to 2008 Forecast. The overall increase in travel is primarily related to additional staff training. The overall increase in meeting expense is primarily related to additional committee and working group meetings. 21 of 32 20

230 SOUTHWEST POWER POOL 2009 BUDGET - SUMMARY INCOME STATEMENT & COMMENTARY (000's) 2009 Budget 2008 Budget 2008 Fcst 2009 Budget Variance As Compared To: 2008 Budget 2008 Fcst Fav/(Unfav) Fav/(Unfav) TOTAL ADMINISTRATIVE & LEASE EXPENSE Administrative 2,821 1,789 2,354 (1,032) -58% (467) -20% Leases 1,090 1, (84) -8% (107) -11% Total Administrative & Leases 3,911 2,795 3,338 (1,116) -40% (574) -17% Total Administrative and Lease expenses have increased 40% as compared to 2008 Budget and 17% as compared to 2008 Forecast. The overall increase in primarily due to additional property taxes related to SPP's jurisdictional status to the Arkansas Public Service Commission. TOTAL COMMUNICATIONS & MAINTENANCE EXPENSE Communications 2,805 2,813 2, % (397) -16% Maintenance 4,893 4,255 4,332 (638) -15% (561) -13% Total Comm & Maintenance 7,698 7,067 6,740 (630) -9% (958) -14% Total Communications & Maintenance expense has increased 9% as compared to 2008 Budget and 18% as compared to 2008 Forecast. Communications include all expenditures related to support of SPP s internal and external networks and telecommunications. Maintenance expense consists of third party maintenance support for SPP s critical hardware and software assets. The increase in both communications and maintenance expense is primarily due to the addition and upgrade of SPP s transmission and market systems. TOTAL OUTSIDE SERVICES Outside Services 16,552 15,524 13,548 (1,028) -7% (3,004) -22% Outside services consist of third party expertise to assist SPP in the deployment of its services and to provide legal representation and satisfy audit requirements. In addition, SPP has also engaged consultants to monitor its markets in an impartial and independent manner. Total Outside Services expense has increased 7% as compared to 2008 Budget and 22% as compared to 2008 Forecast. 22 of 32 21

231 SOUTHWEST POWER POOL 2009 BUDGET - SUMMARY INCOME STATEMENT & COMMENTARY (000's) 2009 Budget 2008 Budget 2008 Fcst 2009 Budget Variance As Compared To: 2008 Budget 2008 Fcst Fav/(Unfav) Fav/(Unfav) TOTAL REGIONAL STATE COMMITTEE Regional State Committee % 1 0% Total Regional State Committee (RSC) expense has increased 1% as compared to 2008 Budget and remains flat as compared to 2008 Forecast. The RSC expects to initiate a cost/benefit study during 2009 to further explore the EHV overlay. TOTAL DEPRECIATION & AMORTIZATION Depreciation & Amortization 20,709 18,540 17,212 (2,169) -12% (3,497) -20% Although Depreciation and Amortization are not components of fs SPP s administrative fee, they are significant factors in SPP s GAAP based budget. Total Depreciation & Amortization expense has increased 12% as compared to 2008 Budget and 20% as compared to 2008 Forecast. The increase is primarily due to currently capitalized project costs expected to begin depreciation in calendar years 2008 and 2009 as well as foundation related capital expenditures in 2008 and TOTAL OTHER EXPENSE Interest Expense 3,524 2,919 2,579 (605) -21% (945) -37% Interest Income (750) (1,000) (942) (250) 25% (192) 20% Total Other Expense 2,774 1,919 1,637 (855) -45% (1,137) -69% Total Other Expense has increased 45% as compared to 2008 Budget and 69% as compared to 2008 Forecast. Other Expenses include interest expense, interest income, bad debt and other extraordinary gains or losses. The increase is due to expected additional debt issuance in 2009 related to capital expenditures. No bad debt or extraordinary gains or losses are expected in TOTAL DEBT REPAYMENT Debt Repayment 8,206 12,206 12,206 4,000 33% 4,000 33% SPP will make a $5,000 principal payment on 2011 Senior Note in June Additionally, SPP will make quarterly principal payments for the mortgage on the Maumelle facility and the new 2014 Senior Note totaling $206 and $3,000, respectively. 23 of 32 22

232 SOUTHWEST POWER POOL RECONCILIATION OF BUDGET ADJUSTMENTS 2009 Budget Adjustments 2009 Budget As Presented to Correction of Vacancy Facility Sr. Policy TOTAL To Present to Finance Comm Merit Incr Estimation Manager Analyst ADJUSTMENTS SPP BOD (000's) Tariff Administration Service 56, ,601 Fees and Assessments 18, ,227 Contract Services Revenue 21, ,538 Study Revenue 4, ,911 Other Income Total Revenue 101, ,602 Salary & Benefits 50, (2,765) (1,777) 48,659 Employee Travel 1, ,504 Administrative 2, ,821 Assessments and Fees 11, ,103 Meetings Communications 2, ,805 Maintenance 4, ,893 Leases 1, ,090 Outside Services 16, ,552 Regional State Committee Depreciation & Amortization 20, ,709 Interest Expense 3, ,524 Interest Income (750) (750) Total Expenses 116, (2,765) (1,777) 114,253 Net Income (14,428) (852) 2,765 (55) (81) 1,777 (12,651) Debt Repayment 8, ,206 MW/h Forecast 331, ,360 Net Revenue Requirement 58, (2,765) (1,777) 56,478 Calculated Admin Fee / MWh $0.176 $ $0.008 $0.000 $ $0.005 $0.170 Recommended Admin Fee / MWh $ $0.000 $0.170 Capital Expense 29, ,637 Headcount Explanation of Adjustments Correction of Merit Increase: This adjustment recalculates the standard merit pool increase from 2.3% to 4.8% for all SPP departments. Vacancy Estimation: This adjustment adds a vacancy factor to SPP's overall staffing expenses. Vacancy is at 7%. Facility Manager: This adjustment adds a Facility Manager to SPP's staff beginning in 3rd Qtr Senior Policy Analyst: This adjustment adds a Senior Policy Analyst to SPP's staff dedicated to support demand response, energy efficiency, and resource planning. This position is expected to be filled in 2nd Qtr of 32 23

233 SOUTHWEST POWER POOL 2009 BUDGET - BALANCE SHEET ($000) 12/31/ /31/2009 ASSETS Current Assets Cash & Equivalents $14,462 $45,546 Restricted Cash Deposits 16,379 16,384 Schedule 12 Deposits 7,704 9,454 Accounts Receivable (net) 8,265 8,015 Other Current Assets 3,061 3,460 Total Current Assets 49,870 82,859 Total Fixed Assets 43,667 52,595 Total Other Assets 918 1,068 Investments TOTAL ASSETS 94, ,977 LIABILITIES & EQUITY Liabilities Current Liabilities Accounts Payable (net) 5,118 5,768 Customer Deposits 16,634 16,384 Current Maturities of LT Debt 7,206 7,206 Other Current Liabilities 12,235 12,494 Total Current Liabilites 41,193 41,852 Long Term Liabilities 4.78% Senior Notes ,000 5,000 Floating Senior Note ,500 23,500 US Bank Mortgage ,575 4,369 Additional Borrowings 62,700 Other Long Term Liabilities 4,843 4,543 Total Long Term Liabilities 45, ,112 Net Income (2,620) (12,651) Members' Equity 10,285 7,665 Total Members' Equity 7,665 (4,986) TOTAL LIABILITIES & EQUITY $94,775 $136, of 32 24

234 SPP 2009 BUDGET SUPPLEMENTAL ANALYSIS Administrative Fee History Headcount Analysis Three Year Income Statement Forecast Three Year Cash Flow Forecast Administrative Fee Sensitivity 26 of 32 25

235 SOUTHWEST POWER POOL ADMINISTRATIVE FEE HISTORY $0.250 $0.200 $0.150 Budgeted NRR/Budget Load Actual Admin Fee Actual NRR / Actual Load $ Budgeted NRR/Budget Load $ $ $ $ $ $ Actual Admin 2004 Fee $ $ $ $ $ $ Actual NRR / Actual Load $ $ $ $ $ Budgeted Net Revenue Required $ 38,322 $ 44,391 $ 45,688 $ 52,819 $ 61,462 $ 56,478 Budgeted Load 245, , , , , ,360 Budgeted NRR / Budget Load $ $ $ $ $ $ Actual Admin Fee $ $ $ $ $ $ Actual Net Revenue Required $ 33,443 $ 38,415 $ 49,549 $ 44,410 $ 53,879 Actual Load 245, , , , ,135 Actual NRR / Actual Load $ $ $ $ $ EIA-411 Load Growth Forecast -0.37% 3.05% -0.60% 1.80% 2.10% 2.40% * Actual Load Growth -1.60% 8.82% 7.19% 5.12% -1.65% * EIA-411 Load Growth Forecast is estimated at 2.40%, however load growth from the Nebraska transmission integration represents a 9.70% increase beginning in second quarter of 32 26

236 SOUTHWEST POWER POOL 2009 BUDGETED HEADCOUNT AS COMPARED TO 2008 FORECAST 2008 Additions 2009 Department Forecast Project Non-Proj Total Budget Officers Accounting Credit Human Resources (a) 18 Settlements Process Integrity (b) 48 Legal (c) 7 Communications Engineering (d) 41 Information Technology (e) 106 Market Development Operations (f) 80 Regulatory (g) 7 Contract Services (h) (i) 417 (a) Administrative support and human resources associated with overall SPP staff growth and facilities (b) 3 FTE for Regional Entity compliance, 3 FTE for SPP compliance, 1 FTE for internal audit, 1 FTE for customer service, 1 FTE for training, and 1 FTE for project management (c) Additional corporate and regulatory legal staff (d) 4 FTE for tariff studies, 2 FTE for transmission modeling, and 2 FTE for the Engineers in Training program (e) 13 FTE for application support, 2 FTE for database management, 3 FTE for service management, and 2 FTE for IT operations (f) 9 FTE are associated with the Balancing Authority Consolidation project which was approved during the 2008 budget process, however, these FTE will likely not be hired until The remaining additional FTE are associated with the Nebraska integration and additional FERC Order 890 requirements. (g) 1 FTE for regulatory analysis and support (h) 1 FTE for supporting demand response, energy efficiency, and resource planning (i) 47 FTE expected to be hired in Q1 2009, 16 FTE in Q2 2009, 3 FTE in Q of 32 27

237 SOUTHWEST POWER POOL 2009 BUDGET - THREE YEAR FORECAST BUDGET FORECAST FORECAST Income Tariff Administration Service $56,601 $59,164 $60,342 Fees & Assessments 18,227 19,138 20,095 Contract Services Revenue 21,538 20,189 (a) 20,189 Miscellaneous Income 5,236 5,236 5,236 Total Income 101, , ,862 Expense Salary & Benefits 48,659 52,112 (b) 57,080 Employee Travel 1,504 1,629 1,783 Administrative 2,821 3,686 (c) 4,124 Assessments & Fees 11,103 11,658 12,241 Meetings Communications 2,805 3,144 3,437 Maintenance 4,893 6,371 (c) 5,803 Leases 1, (c) 77 Services 16,552 13,837 15,428 Regional State Committee Depreciation & Amortization 20,709 13,231 (d) 14,526 Other Expense 2,774 4,697 3,797 Total Expense 114, , ,189 Net Income (Loss) (12,651) (7,543) (13,327) Debt Repayment 8,206 15,206 (e) 16,206 MWh Forecast 331, , ,363 Net Revenue Requirement 56,478 68,411 75,079 Calculated Admin Fee / MWh $0.170 $0.197 $0.212 Recommended Admin Fee MWh $0.170 $0.170 $0.170 Capital Expense 29,637 47,368 25,197 Headcount (b) 491 Fixed Charge Coverage Ratio Growth Assumptions: (a) Assumes renewal of ICT and ITO agreements in 2010 (b) Additional staffing of 38 FTEs each in 2010 and 2011; of them 22 are associated with future markets in 2010 and 33 in 2011 (c) Lease reduction associated with purchase of new facility; other expense items are also impacted due to owning a facility such as maintenance, communications, services and administrative expense (d) Reduction in depreciation expense in 2010 & 2011 due to run-off of existing EIS Market asset (e) Assumed 2009 debt issuance would result in $5.0MM principal payments in 2010 & of 32 28

238 SOUTHWEST POWER POOL THREE YEAR FORECASTED CASH FLOW Account Description QTR QTR QTR QTR OPERATING CASH (000) Beginning Cash on Hand $16,738 $11,397 $7,996 $10,966 $14,786 $10,478 Income Tariff Administration Service 12,969 14,370 14,648 14,614 59,164 60,342 NERC Fees 1,781 1,781 1,781 1,781 7,480 7,854 Contract Services Revenue 5,371 5,371 5,371 5,426 20,189 20,189 Tariff & Transmission Studies 1,001 1,272 1,333 1,305 4,911 4,911 Other Income Operating Income 21,203 22,875 23,214 23,207 92,069 93,621 Expense Salaries Expense 12,261 8,436 8,569 8,596 34,729 38,039 Employee Benefits Expense 2,184 2,256 2,299 2,218 9,255 10,137 Payroll Taxes Expense ,919 3,197 Travel Expense ,629 1,783 Administrative Expense 1, ,686 4,124 Meetings Expense Communications Expense ,144 3,437 Maintenance Expense 2,391 1, ,371 5,803 Leases Expense Outside Services Expense 4,806 4,573 3,776 3,397 13,837 15,428 Regional State Committee Expense Interest Income & Expense ,697 3,797 Debt Service 801 5, ,206 16,206 Operating Expense 26,544 26,276 20,244 19,386 96, ,922 Ending Cash on Hand $11,397 $7,996 $10,966 $14,786 $10,478 $1,177 Recommended Admin Fee MW/h $0.170 $0.170 $0.170 $0.170 $0.170 $0.170 CAPITAL CASH (000) Beginning Cash on Hand ($2,277) $19,783 $14,723 $12,269 $30,760 $3,392 Capital Expenditures 9,029 5,979 4,905 9,725 47,368 25,197 Equipment Financing 30, , ,000 Real Estate Financing 1, ,451 8,216 20,000 0 Ending Cash on Hand $19,783 $14,723 $12,269 $30,760 $3,392 $195 TOTAL CASH (000) $31,180 $22,719 $23,235 $45,546 $13,870 $1, of 32 29

239 SOUTHWEST POWER POOL ADMINISTRATIVE FEE SENSITIVITY $25.0 $20.0 $15.0 $10.0 $5.0 $0.0 ($5.0) ($10.0) ($15.0) Operating Cash Balance (millions of dollars) $0.160 $0.170 $0.180 $0.190 Cash Balance Admin Fee $ $14.5 $11.5 $3.7 ($9.1) $ $14.5 $14.8 $10.5 $1.2 $ $14.5 $18.1 $17.3 $11.5 $ $14.5 $21.4 $24.0 $ of 32 30

240 Southwest Power Pool, Inc. FINANCE COMMITTEE Recommendation to the Board of Directors October 28, Administrative Fee Organizational Roster The following persons are members of the Finance Committee: Harry Skilton, Chair Larry Altenbaumer Trudy Harper Kelly Harrison David Sartin Gary Voigt SPP Director SPP Director Tenaska Westar AEP Arkansas Electric Background Section 8.4 of the SPP Bylaws requires SPP to annually develop an assessment rate based on budgeted expenditures for the upcoming fiscal year and estimated billing determinants for that year. Analysis The 2009 SPP operating budget indicates a net revenue requirement ( NRR ) for the year of $58,256 and estimated billing determinants of 331,360 GWh. The rate is determined by dividing the NRR by the estimated billing determinants which results in a rate of 17.6 /MWh. NRR is derived by adjusting SPP s gross cash outflows (exclusive of capital expenditures) by all non administrative fee revenue forecast to be earned in the year. The billing determinants are calculated by adjusting the current year s run rate by the growth factor published in the most recent EIA-411 report. SPP s cash forecast indicates a rate of 17.0 /MWh is sufficient to fully fund SPP s operations during the 2009 year as well as through 2010; an increase to 18 /MWh is expected for Funding requirements in 2010 and 2011 are based on numerous assumptions 1, should real time experience differ meaningfully from these assumptions, SPP s ability to operate at our current forecasted administrative fee may be jeopardized. SPP is able to maintain a rate below its expected costs to be incurred during 2008 due to its 2007 expenses being below expectations and its 2007 revenues being above expectations. Recommendation The Finance Committee recommends the SPP Board of Directors establish an assessment rate and tariff administrative fee (schedule 1) of 17.0 /MWh beginning on January 1, Approved: Finance Committee September 19, 2008 Action Requested: Approve Recommendation 1 load growth, membership stability, financing arrangements, implementation of consolidated balancing authority, development of future markets, etc. 32 of 32

241 Markets & Operations Policy Committee John Olsen Chair Bill Dowling Vice Chair

242 Overview Action Items Tariff Language for NE BPF Informational Items CBTF Preliminary Results and Direction MWG PRR 176 CBASC Future Direction RTWG GQTF, DPATF, 3rd Party Impacts Wind Integration Consent Action Items (Only covered if questions) Criteria 5 Attachment AP Sponsored Upgrade Agreement PRR 184, 186 Schedule 2 Waivers Unintended Consequences Out of Cycle Projects 3 Action Items 4

243 Waiver Request Westar Central Plains Wind October Summary of Waiver Request Westar reservation studied in 2007-AG2 Westar requesting 99 MW from Central Plains Wind farm Base Plan Funding (BPF) potential calculated in AFS-6: 9.9 MW x $180,000/MW = $1,782,000 Based on 10% nameplate net dependable capacity for wind E & C upgrade allocation in AFS-6 study posting is $8,500,000 Iatan-Stranger Creek KCPL upgrade $6,718,000 to be directly assigned to Westar September 15, 2008 Letter Westar requests waiver Recommendation to SPP Board of Directors within 120 days per the tariff required not later than January Next SPP Board of Directors meeting October 28,

244 Waiver Request Discussion The following SPP recommendation based on current SPP Tariff SPP is aware of policy issues raised by this waiver Policy decisions under consideration by CAWG/RSC, if approved, could significantly impact this recommendation 7 Attachment J Section B.3 Cost of Network Upgrades associated with new or changed Designated Resource shall be classified as Base Plan Upgrades if they are less than or equal to $180,000/MW times the lesser of : (a) the planned maximum net dependable capacity applicable to the Transmission Customer or (b) the requested capacity (the Safe Harbor Cost Limit ) 8

245 Net Dependable Capacity - Generally Net capability defined by NERC: Net dependable capacity - maximum capacity a unit can sustain over an specified period, modified for seasonal limitations and reduced by the capacity required for station service or auxiliaries Summer net capability of each unit may be used as winter net capability without further testing, at the option of the member (See SPP, FERC Electric Tariff, Fifth Revised Volume No. 1, Original Sheet No. 941) 9 Waiver Request Discussion Attachment J, Section C.2.ii - Allows all or part of excess above Safe Harbor Cost Limit to be classified as Base Plan Upgrade Cost, taking into account extent to which commitment to new or changed DR exceeds five-year commitment Westar reservation is a 10-year reservation SPP recommends increase of $38,981 from initial $1,782,000 Base Plan Funding Based on same calculation used for OGE / GSEC/ EDE waivers and MW-MI calculation - indicating seven zones benefiting from this commitment 10

246 SPP Conclusions and Waiver Recommendation Current SPP Tariff - Net Dependable Capacity to be used for calculating Safe Harbor Cost Limit for all resources, including wind SPP cannot waive Tariff provisions Recommends a Waiver for the Commitment in Excess of Five Years Total Base Plan funding increase - $38,981 Total Base Plan Funding with Waiver based on the current Tariff provisions- $1,820, Proposed additional language for Wind Generation for Attachment J Section III.B Language is under discussion by RTWG. Approval of MOPC and Board of Directors are also needed prior to filing of Tariff revisions with FERC In addition if the Designated Resource requested is derived from a wind generation plant, the total capacity derived from wind generation with firm transmission, including the requested capacity of the new resource, shall not exceed 20% of the Transmission Customer s projected system peak load responsibility in the first year the Designated Resource is planned to be used by the Transmission Customer as determined pursuant to SPP Criteria 2. Intent is to limit Base Plan Funding for wind resources to 20% of Customer s peak load responsibility due to operational concerns Westar meets this test 12

247 Proposed additional language for Wind Generation for Attachment J Section III.A.3 Based on this proposed language 33% of the $8.5M KCPL upgrade ATRR would be directly assigned ( DA ) to WR with 67% regionally funded. The DA component to WR is $2,805,000. The remainder of $5,695,000 would be regionally funded Waiver Request Discussion The Aggregate Study is a N-1 analysis The Aggregate Study process does not include analysis on a flowgates basis Westar stated the flowgate upgrade would provide regional benefit if eliminated. It does not seem appropriate to respond to the need to upgrade a flowgate as this would create a more complex study process. CAWG may need to discuss the tariff language needed regarding variance of BPF specific to flowgates 14

248 Waiver Recommendations CAWG Recommendation CAWG recommends granting Westar a waiver in accordance with the RSC approved new policy for the direct assignment portion for the wind resources. Directly assign 33% to Westar ($2.8MM Cap) Regionally fund 67% Staff Recommendation The recommendation of the Staff is to provide an additional Base Plan funding of $38,981 based on the 10 year reservation and existing tariff provisions. The Staff acknowledges that a policy revision that has been approved by the CAWG/RSC; that is ultimately approved through the SPP/FERC process would alter the resulting recommendation Recommendation The MOPC recommends that the Board of Directors approve the Westar waiver as outlined by the CAWG with no dollar cap. Approved Unanimously MOPC (2 Abstentions Westar, EDE) 16

249 Tariff Language for NE Base Plan Funding 17 Status of NE Integration Transition Teams have finalized their transition plans and schedule under active SPP Project Management Weekly Coordination calls with NE entities September 2008 SPP filed Tariff and Bylaws changes and Membership Agreement Amendments filed with FERC, expect answer around December 1 Outstanding issue with how NE would enter Base Plan Funding Need to resolve for filing and putting their facilities under the tariff Filing before November 1 to meet April 1, 2009 transition to SPP SPP Staff reviewed NE projects and proposed a method to include NE Reviewed by TWG on September 2008 asked the MOPC for direction on the proposal from SPP Staff 18

250 MOPC Review MOPC debated the SPP Staff proposal: 1. Nebraska entities will be responsible for the costs of all Nebraska projects needed prior to January 1, 2009, including those identified by SPP Staff for the Nebraska facilities to meet SPP Criteria and NERC Standards. 2. Nebraska entities will pay the BPF rates for all SPP projects that are needed for reliability or transmission service on or after January 1, These facilities can be under construction prior to January 1, Nebraska entities will also pay their load ratio share of the 1/3 Regional Component of BPF rates for all SPP BPF projects including those needed before January 1, All Nebraska projects needed and completed on or after January 1, 2009, as identified by SPP Staff to meet SPP Criteria and NERC Standards or identified by the Nebraska entities with SPP Staff agreement, for reliability or transmission service over Nebraska entities facilities will be eligible for BPF. These facilities can be under construction prior to January 1, To the extent that network upgrades that are needed on or after January 1, 2009 but completed prior to January 1, 2009 and are components of both the Phase 1 of the NPPD 345kV Norfolk to Lincoln (ETR) project and OPPD Sub 1255/3455 Transformer project, such network upgrades will be included in the 1/3 Regional Component of BPF MOPC Action MOPC Approved (1 No SPS, 1 Abstention EDE): The SPP Staff recommends that the MOPC endorse the proposal to include the Nebraska entities in Base Plan Funding and direct the RTWG to use the attached tariff language and modify, including any non-substantive changes required, for recommendation to the SPP Board of Directors at the October 28 meeting for approval for filing by November 1, RTWG Approved on October 23 the tariff language included for the Board of Directors action 20

251 Recommendation The MOPC recommends approving the RTWG approved tariff language for filing on or about November 1, Information Items 22

252 Cost Benefit Task Force 23 Project Overview Measure the cost and benefits of moving from the current SPP EIS market structure ( base case ), including implementation of the 2007 SPP Transmission Expansion Plan (STEP), to the market structures of the following Change Cases: Change Case I Day-Ahead Market with Unit Commitment Addition only Change Case IIA - Day-Ahead Market with Unit Commitment and Cooptimized Ancillary Service Market (All Inclusive with FTR & TSRO Sensitivities) Change Case IIB - Day-Ahead Market with Unit Commitment 2009, 2010 and All Inclusive (FTR & TSRO Sensitivities) Change Case IIC - Co-optimized Ancillary Service Market 2009, 2010 and All Inclusive (FTR & TSRO Sensitivities) Change Case III Ancillary Service Market Addition only Change Case IV Simplified Day-Ahead Market with Unit Commitment (Qualitative analysis only) 24

253 Wind Assumptions 4,270 MW of wind facilities modeled at most likely locations (nodes) Moderate wind penetration assumption for consistency with transmission expansion plan and to avoid weighting the market design decision based on wind levels 1. Same wind schedules across Base Case and all Change Cases reduce cost differentials 2. Annual capacity factor 38.6%, varying monthly between 26% summer and 58% spring Generic hourly wind patterns entered to reflect hourly wind variation but lack of intra-hour volatility modeling increases perceived market benefits Each new wind facility assigned to an SPP Member, no new IPP wind Wind given highest priority on transmission grid, i.e. wind curtailed as extreme last resort 25 Cost and Benefit Measures Quantify benefits of market changes using simulation model to compute Adjusted Production Cost (APC) for Base case and all Market change scenarios APC = Generation Cost (Fuel, VOM, Emissions) + Purchase Cost Sales Revenue 1. SPP in Total 2. Market Participants 3. State by State 4. Balancing Area Estimate ranges of Market Change Implementation Costs 1. Hardware and software costs 2. Staff Training 3. Administrative Costs 26

254 Total Net Benefit by Case Summary Total SPP Net Benefit Case Description % Benefit Avg Yr Benefit ($M*) Case I DAM Only 2.5% 4.3% Case II DAM & ASM w/ FTR or TSRO 3.0% 5.7% Case III ASM Only.3%.4% *(2008 $, 6% Discount Rate) Note: All values may be different in the finalized written report 27 Market Design Net Benefit Observations All analyses have indicated a benefit in excess of costs in all scenarios Combining DAM and ASM has the greatest cost-benefit impact, producing significantly more benefit than implementing each market separately DAM allows more efficient utilization of coal and CC and reduces use of CTs and Steam Gas Turbines DAM benefit is a significant benefit over ASM; Primary benefit is to move towards a DAM first if market implementation is staged 28

255 SPP 2012 Average Load Hub Prices Comparison Base Case to Change Case II Current EIS Market Prices DAM & ASM Prices Percent Change CSWS - AEPW EDE GRDA KACY KCPL Mid-Kansas Midwest OKGE OMPA SECI SPS WEFC WRI $/MWh 29 SPP Generation Impact Change in Generation between Current EIS to DAM/ASM Markets Change Case IIA Generation Impact 15, ,000.0 GWH 5, (5,000.0) (10,000.0) Combined Cycle Combustion Tur ST Coal ST Gas 30

256 General Observations Regarding ISO Costs SPP Implementation and Ongoing Costs Change Case I: MM$ Change Case II: MM$ 1. Depends on phase-in and financial configuration Change Case III: MM$ Actual consulting dollars incurred by other ISOs generally have exceeded original estimates in transitioning markets Market trial costs and training were typically under estimated Market start is often delayed Cost begin 2-3 years prior to market start-up 31 Southwest Power Pool Administration Fee Impacts of Future Market Options Estimations Day Ahead Market Day Ahead Market with ASM ASM Only Admin Fee Admin Fee Admin Fee $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $

257 SPP - Market Participant Range of Costs Base Initial Install Costs Systems Costs SPP Change Case Adaption Costs Ongoing Costs Personnel Costs (Training, Testing, etc) Lo Hi Lo Hi Lo Hi Lo Hi Total (1000's) SCADA (AGC) Unit Commitment Bid Strategy ISO Communications Settlement FTR/TSRO Analysis Note 1: Unit Commitment does not apply for Change Case III; Note 2: FTR/TSRO Analysis applies only to Change Case II Total Range of Market Participant Costs: $ $6.23 M 33 General Observations Regarding Members Costs Complexity of transactions was a key factor in determining market design costs for Members Difficult to obtain necessary information due to competitive nature of market trading strategies Cost effort relied heavily on Ventyx market experience Options available to Members include self build infrastructure or outsource Market trials provide good opportunity to test systems and staff training and should be utilized Training of staff is typically under estimated and occurs too late in the schedule to maximize market trial experience 34

258 Next Steps CBTF continuing to review: Market Participant Level Benefits State-wide Level Benefits Balancing Authority Level Benefits Chair of MOPC directed the MWG to bring to January MOPC meeting: Proposal for future market steps Plan, schedule, cost for implementing recommended proposal Include the consolidation of balancing authorities 35 Additionally requested analysis MOPC requested additional benefits sensitivities: Ventyx is currently estimating time & cost Reduce Gas price for study year 2012 by 25%; run base case and change case II (all-inclusive) Reduce Wind generation by half for a high wind study month in 2012; run base case and change case II (all-inclusive) RSC requested a high wind analysis: Ventyx has provided an estimate for a thorough high-wind analysis that will determine transmission upgrade locations and net benefit changes for Change Case II 1. Two months to complete; $73k-$100k based on two options 36

259 Questions? 37 Detailed Southwest Power Pool Cost Estimates for Future Market Options $ in 1000s Day Ahead Market Day Ahead Market with ASM ASM Only Total Total Total $2,268 $2,623 $ $4,445 $5,129 $ $15,482 $20,720 $5, $19,294 $22,557 $6, $20,260 $23,686 $7, $21,279 $24,870 $7, $22,344 $26,115 $8,

260 Detailed Southwest Power Pool Capital Expenditures Cost Estimates for Future Market Options $ in 1000s Day Ahead Market Day Ahead Market with ASM ASM Only Total Total Total 2009 $1,381 $1,891 $ $14,684 $21,359 $6, $14,766 $20,466 $5, $1,204 $2,404 $1, $32,035 $46,120 $14, MWG 40

261 PRR 176 Demand Response Protocol Revision Request to clarify and enhance the requirements for Demand Response to participate in the SPP EIS Market ORWG review and Impact Analysis is needed for MWG and MOPC action ORWG review Mid November MWG review of Impact Analysis Oct May require an interim MOPC meeting in November to bring the tariff changes to the Board of Directors at it s December 7 th meeting 41 Consolidated Balancing Authority Steering Committee 42

262 Current Status and Direction Given CBASC consensus is that benefits with current proposal for CBA would only be realized as a transition to future market steps. CBASC was concerned with further design and its impact on the future market steps. Chair of MOPC directed CBASC to determine if there are additional design or proposal that would provide the benefits expected without future market steps and coordinate with MWG to insure minimal duplication or throw away work 43 RTWG 44

263 Generation Queue Task Force 45 Issues The number of Generation Interconnection requests are at an all time high Currently 198 Interconnections somewhere in the queue representing 49,103 MW. Being fueled by the current building of wind generation stations RTWG formed the GQTF in early Mission is to speed-up the processing of large generator interconnection requests Attachment V GQTF has 15 members composed of: 1. TOs (9), renewable developers (5) and marketers (1). 2. Chair: Steve Ferry, MKEC 46

264 Current and Proposed Process Currently a sequential process for studies Feasibility, Preliminary and Definitive impact and Facility Original request can be suspended for up to 3 years Potentially shifts costs to subsequent request Proposed process changes Remove feasibility study from critical path. Make System Impact Study and Facilities Study stand alone milestones No more overall-process queue position Increase cost of entry and associated fees 47 Proposed Process Cont d Milestones Feasibility Study (Milestone set 1, but not required) Preliminary Impact Study (Milestone set 2) Definitive Impact Study (Milestone set 3) Facility Study (Milestone set 4) Interconnection Agreement (Milestone set 5) Upfront Milestone Deposit Deposit amounts vary by the size of the request May not be refunded if request is withdrawn Customer only charged actual cost of the study 48

265 Deposits Milestone Request MW Deposit 1- Feasibility Study 2 - Preliminary Impact Study 3 Definitive Impact Study All Requests, but is Optional < 100 MW 101 MW to 800 MW > 800 MW < 75 MW > 75 MW 4 Facility Study All Requests 5 Interconnection Agreement All Requests $10,000 $40,000 $60,000 $90,000 $75,000 $150,000 None, but need the letter of credit None 49 Proposed Process Cont d Clustering Many generators in same geographical area Designed to minimize costs and propose more logical network upgrades Allow SPP staff to group requests into logical groups 1. Geographical 2. Electrical 50

266 Additional Fees Suspension Fees are the greater of the allocated cost of the Network upgrades or the following: > 100MW months no additional payment months - $5,000,000 <100 MW but >50MW months no additional payment months - $2,500,000 <50MW months no additional payment months - $1,000, Next Steps RTWG/GQTF will be modifying tariff language to support the new proposed process for Generation Interconnection Targeting Jan 09 series of meetings for approval 52

267 Delivery Point Addition Task Force 53 Issue SPP s OATT is very detailed how to add new resources but has virtually nothing on adding new delivery points for NITS customers Many NITS customers have multiple Delivery Points (DP) Each DP must be detailed in the NITS agreement Usually cover large geographical area DP s are usually small (less than 5 MW) Many DP s are on distribution facilities Adding new DPs are usually time sensitive Strict interpretation of current OATT could require each new delivery point to go through the Aggregate Study process 54

268 DPATF RTWG formed Delivery Point Addition Task Force (DPATF) - Chair: Robert Pennybaker, AEP: Better define the process of adding new delivery points Streamline the tariff process where practical Customer to provide notice to both: TO will study local area issues SPP to review larger issues Cost of non-transmission facilities follow local owner s rules Additional studies and cost only occur if load causes problems on the transmission system Any requests related to new Service Requests or New Designated Resources would follow current rules 55 New DPATF Process 56

269 Proposal on 3 rd Party Impacts 57 Issue Tariff Requires the identification of flow impacts on non-spp systems (Sect. 21) Transmission Customer (TC) responsible for handling 3 rd party impacts, SPP is to assist Issues: No time limit for getting a response from 3 rd party Delays from 3 rd party can delay the completion of the Aggregate Study process No standard cost allocation methodology on 3 rd party systems or impacts 3 rd party impacts can be significant SPP-2007-AG3-AF4 has 40 3 rd party impacts Issue expected to increase with time, especially in support of the Balanced Portfolios and the EHV backbone 58

270 Proposal For 3 rd Party that has a JOA or seams agreement with SPP Follow agreement Begin work on creating or modifying agreement to improve cost allocation issues For 3 rd parties that have not executed a JOA or seams agreement with SPP Modify the SPP Tariff to put in specific response times for 3 rd Parties Possibly create a methodology to by-pass those requests waiting on results from 3 rd parties Explore the possibility of creating a set of standard set of rules (basic seams agreement) to be used if no specific JOA or seams agreements are signed 59 Action Chair of MOPC assigned to BPWG 60

271 Wind Integration 61 Wind Integration Concerns Major 2009 Wind Integration Study Budgeted Leveraging National Renewable Energy Lab (NREL)/DOE data and Eastern Wind Integration and Transmission Study (EWITS) Determine planning and operational impacts to SPP of further wind development Generation Interconnect queue heavily loaded with wind interconnect requests Total generation nameplate value of requests approaching 45GW 62

272 Case Study Proposal - SPS Wind Pushing SPS System Reliability Ideal test case Many wind providers see SPS system as prime opportunity because of combination of high wind, load and existing network Many behind the meter distribution turbines not studied Qualifying Facilities Supplemental AMEC analysis to focus on SPS area AMEC Earth & Environment, Inc. (AMEC) Study addressing 1. Wind data collection 2. Operating reserve requirements 3. Wind forecast error 63 Benefits of a Supplemental AMEC Study Quickly Identify system limits for SPS Area Analysis results by end of 2008 Provide specific system data by which judgment can be made about accepting new generation into the Generation Interconnect queue evaluation process. AMEC performs analysis for which Staff resources, tools and skills do not exist While unbudgeted, these are relatively small expenditures that Staff believes are critically important in today s environment 64

273 MOPC Action MOPC approved SPP staff recommendation of an unbudgeted expenditure to proceed with the $129,000 project outlined in the Southwest Power Pool Penetration for SPS Area Supplement so that it can be completed in the fourth quarter of Future Work MOPC forming Wind Integration Task Force (WITF) Consist of 7-12 members 1. X TO, X TDU and marketers WITF to address many issues, including the following: 1. SPS Wind Penetration Study 2. Limitation on the amount of wind based on the current structure, planning and operational standards A. Changes in the following areas: a) Consolidation of Balancing Authorities b) Transmission expansion to facilitate deliveries both within and external to SPP c) Operating Reserve and Regulation Requirements d) Ancillary Services Markets e) Day-Ahead Markets 3. Potential benefit of regional diversity for the wind patterns 66

274 Consent Items 67 Criteria 5 Additional Specification 68

275 ORWG Recommendation Changes propose specific kv levels and types of facilities that the Reliability Coordinator would be required to study and provide approval for scheduled outages is identified. Requirements for submitting information concerning forced outages of these specific kv and types of facilities to the RC also are listed. Also added is the requirement of members to submit Operational Flow Orders (OFO s) and Critical Notices from their gas suppliers to the RC MOPC recommendation The MOPC recommends that the Board of Directors approve the changes to Criteria 5 it proposes. ORWG approved unanimously MOPC approved unanimously under consent agenda 70

276 Attachment AP NERC Penalties 71 NERC Penalties On March 20, 2008, FERC released an Order Providing Guidance on Recovery of Reliability Penalty Costs by RTOs & ISOs Prior to a Customer being charged, the following must occur. There must be a notice to the customers in the OATT No charge can be assessed without a 205 filing RTWG drafted Attachment AP to provide the notice to customers 72

277 Attachment AP Provides Notice to all Market Participants (MP) and Members that they may be assessed a NERC penalty Describes the general procedure for how SPP will design the 205 filing with FERC when proposing to assess a penalty 1. Propose direct assignment if it can be determined (Sect. 2) 2. Spread Costs over some or all MP & Members if violation can not be directly assigned (Sect. 3) Does NOT contain any rates nor does it grant any authority to SPP or NERC to recover penalties from specific entity(ies) with out FERC approval Recommendation: The MOPC recommends the Board of Directors approve the tariff language for the newly created Attachment AP. Approved unanimously - RTWG Approved unanimously - MOPC 74

278 Sponsored Upgrade Agreement 75 History The SPP has provisions in the OATT for allowing someone to Sponsor an upgrade This proposal puts into place a Pro-forma agreement that specifies the rules on: How a Sponsor pays for an upgrade How are the costs calculated How credits are paid Term of the agreement 76

279 Sponsored Upgrade Agreement Agreement only covers cost issues, follows tariff rules as far as construction, review, credit policy, etc. Agreement based on same principal as the longterm PTP upgrade procedures, but with a zero MW transmission request The term can be from 0 to 20 years Costs calculated on a Net Present Value basis assuming a 20 year life Credits The Sponsor is eligible to receive credits pursuant to Z2 Credits Stop: When the Sponsor is fully paid, or When the project is removed from service No guarantee of payback 78

280 Other changes Attachment J Recovery of Costs Some minor wording changes clarifying the use of Sponsored Upgrade Expanded Part V.A, Sponsored Upgrades 79 Recommendation: The MOPC recommends that the Board of Directors approve the Tariff changes allowing the RTWG to make any nonsubstantive changes to the Tariff language necessary for filing at the Commission. Approved unanimously RTWG Approved unanimously MOPC (1 abstention ITC). 80

281 PRR 184, MWG 81 PRR184 - Supplemental Language for PRR 113 PRR 113 reflected changes to Section 3 of the Protocols specifically in the Resource Plan Operational usage of the data and references in other sections of the Protocols were not updated causing conflicts within the document System design of the Profiled Ramp Rate capability is also more flexible than originally submitted in PRR 113 This PRR modifies the ramp rate section to reflect system development enhancements 82

282 PRR URD Penalty Charges Removal from Dispatch section actually reduces available ramp capability and capacity availability Adversely impacts market operations and provides little or no incentive to Market Participants to follow dispatch instruction PRR 187 (URD Calculation Changes/Charges) is addressing additional penalty incentives to alleviate this issue and under consideration/review by the MWG Approved in the MWG with one no vote (Westar) Westar voted no to the following: As approved, would allow a resource not following deployment instruction to set LIP if it is the marginal Resource. In our opinion: a Resource, who is not following Deployment Instruction and therefore may be effecting reliability and regulation, should NOT benefit from the price of its offer curve or higher Recommendation: The MOPC recommends the Board of Directors adopt the approved Protocol Revision Requests for incorporation into the Market Protocols. Approved unanimously RTWG Approved unanimously MOPC 84

283 Reactive Compensation Schedule Implementing Schedule 2 SPP is in the process of Implementing the new Schedule 2 Have refunded the Schedule 2 amounts paid through May 31, 2008 In the process of calculating the new charge and will bill and distribute the revenue by the end of the year In the process, we noted some discrepancies in the language, Non-substantive changes that occurred when it went from an annual charge to a monthly charge These modifications are shown in the redline document in the advance package 86

284 Recommendation The MOPC recommends that the Board of Directors approve the non-substantive tariff language modifications of Schedule 2. Approved Unanimously RTWG Approved Unanimously - MOPC 87 Waiver Request City of Coffeyville, Kansas October

285 Summary of Waiver Request The City of Coffeyville, Kansas (CMLP) reservation studied in 2007-AG3-AFS-4 CMLP currently has 114 MW of GRDA as a resource. September 11, 2008 Letter CMLP requests waiver This request is for an incremental increase of GRDA service profiled to meet a load increase of 16 MW in 2008 to 197 MW in Based on the first year of the start of the Designated Resource (DR) without redispatch of 2011, the Base Plan Funding (BPF) maximum calculated in AFS-3 would be: 91 MW x $180,000/MW = $16,380,000. Based on the first year of the start of the DR with redispatch of 2010, the BPF maximum calculated in AFS-4 would be: 25 MW x $180,000/MW = $4,500,000. $4.25 million of CMLP-owned upgrades are not eligible for BPF because these facilities are not jurisdictional to SPP. Allocated E & C upgrades eligible for BPF was $6.1 million; based on BPF of $4.5 million, $1.6 million directly assigned to CMLP 89 Coffeyville Load Growth Forecast Summer Load Forecast Demand Major Upgrades $6M 270 reconductor upgrade Major Upgrades $1.2M reconductor plus $4.25M city owned upgrade MW Year 90

286 Summary of Waiver Request After posting AG3-4 CMLP withdrew reservation a smaller profiled resource request for incremental increase of GRDA service profiled with a load increase from 16 MW in 2008 to 115 MW in The next study posting for reservation would probably include eligible upgrades of $10 million expected of which $7 million of the upgrades are required by Recommendation to SPP Board of Directors is due within 120 days per the Tariff or not later than January 9, 2009 Next SPP Board of Directors meeting October 28, Waiver Request Discussion Attachment J, Section III.C.2.ii - Allows all or part of excess above the Safe Harbor Cost Limit to be classified as Base Plan Upgrade Costs, taking into account the extent to which commitment to the new or changed DR exceeds the five-year commitment CMLP reservation is a 34-year reservation 92

287 Waiver Recommendation SPP Recommendation SPP recommends approval of the waiver request to fully fund the project excluding the CMLP-owned direct assignment upgrades 1. Based on the commitment in excess of five years (29 years) and; 2. Realizing anticipated Safe Harbor limit using 91 MW calculation would allow fully funding the project excluding the CMLPowned direct assignment upgrades 3. CAWG may need to address the tariff language needed regarding profiled studies CAWG Recommendation The CAWG is recommending that the SPP RSC recommend to the SPP Board of Directors to grant the waiver request excluding the CMLP direct assignment upgrades 93 Recommendation The MOPC recommends that the Board of Directors approve the CMLP waiver request to fully fund the projects excluding the CMLP-owned direct assignment upgrades, based on the 34 year reservation and realizing anticipated Safe Harbor limit using 91 MW, would allow fully funding the project with the exclusion of the CMLP-owned direct assignment upgrades. Approved Unanimously MOPC (1 Abstention SPS) 94

288 Unintended Consequences 95 Background According to Attachment J of the SPP Tariff For each SPP Transmission Expansion Plan, the Transmission Provider shall calculate the cost allocation impacts of the Base Plan Upgrades to each Transmission Customer within the SPP Region. The results will be reviewed for unintended consequences by the Regional Tariff Working Group and reported to the Markets and Operations Policy Committee and Regional State Committee. 96

289 Base Plan Projects Summary 97 Commitment Horizon 2006 STEP BOD approved reliability projects needing financial commitment within first two years STEP BOD approved reliability projects needing financial commitment within first four years 98

290 Base Plan Upgrades in STEP Includes all base plan reliability projects in 2007 STEP 13 Base Plan Upgrades were not calculated because they were already evaluated in the 2006 STEP, 2 yr commitment horizon. 147 Projects & $467.4M E&C Costs Project lists available in the following worksheet: Base Plan Upgrades 2007 STEP.xls in tabs: 2008 Project List (Branch_Xfmr) 2008 Project List (Device) 99 Direct Assigned Projects Allocation Methodology All Base Plan Upgrades with an E&C cost of $100,000 or less. All ATRR assigned to host zone Subtotals 17 projects $0.8M E&C Costs 100

291 No MW-MI Impacts Allocation Methodology 33% Regional and 67% to host zone Subtotals 60 projects $41.4M E&C Costs MW-MI Impacts Allocation Methodology 33% Regional and 67% to zones based on MW- MI Sum of Positive Impacts Only methodology with a $100k E&C minimum allocation Subtotals 70 Projects $425.2M E&C Costs 102

292 Conclusions for Allocations AEP and SPS received the largest allocations of these projects, but about 65% of the total E&C cost came from upgrades in these two zones ATRR Allocations by Zone 104

293 2009 ATRR Allocations by Zone ATRR Allocations by Zone 106

294 2011 ATRR Allocations by Zone Conclusion Staff s analysis supports a finding of no unintended consequences with respect to the cost allocations associated with the projects eligible for base plan funding in the STEP. Results seem reasonable with host zone getting majority, if not all, of the 67% zonal allocations 108