Southwest Power Pool REGIONAL TARIFF WORKING GROUP May 6, 2004 AEP Offices Dallas, TX 8:30 a.m. - 4:00 p.m.

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1 Southwest Power Pool REGIONAL TARIFF WORKING GROUP May 6, 2004 AEP Offices Dallas, TX 8:30 a.m. - 4:00 p.m. Agenda Item 1 Call to Order, Introductions and Receipt of Proxies Ricky Bittle (Chair) called the Regional Tariff Working Group (RTWG) meeting to order at 8:30 a.m. with a round of introductions. Other RTWG members in attendance were: Gene Anderson (OMPA), Dennis Bethel (AEP), Bob Bowser (KEPCo), David Brian (ETEX), David Grover (Xcel Energy), John Gunesch (OG&E), Ron Kite (KCPL), Mike Proctor (MPSC), Dennis Reed (Westar Energy), Tracey Hannon for Jim Sherwood (SWPA), Jim Stanton (Calpine), Bary Warren (Empire), Mitch Williams (WFEC), Pat Bourne (SPP), Roy Sundman (SPP). Others in attendance included: Joyce Davidson (OCC); Larry Holloway (KCC); Alan Derichsweiler (WFEC); Robert Shields (AECC); David Kays (OG&E); Terri Gallup, Tim Hostetler and Jay Toungate (AEP); Bernie Liu and Wes Berger (Xcel Energy) and Bruce Rew (SPP). Those attending by phone include Carl Huslig (Aquila) and Tom DeBaun (KCC). Agenda Item 2 Review of Agenda and Additional Agenda Items The agenda was approved with the addition of two items: a discussion of limitation of liability language for inclusion in the SPP OATT and discussion of a question from the Market Working Group regarding charges for transmission of imbalance energy (Attachment 1 Agenda As Amended). Agenda Item 3 Approval of Minutes The minutes of the April 8, 2004 meeting were approved (Attachment 2 4/8/04 Minutes). Agenda Item 4 OPC, Board and Members Meetings Reports Dennis Reed (Westar Energy) stated that Markets & Operations Policy Committee (MOPC) had approved all issues brought to it by the RTWG except the proposed Transmission Facilities Definition. Several votes were taken on radials inclusion options with no approval of any of the options considered. The MOPC consensus was that the RTWG should: 1) revise the definition and bring back specific Tariff language, 2) work with the Regional State Committee, and 3) report on any analysis that can be performed considering the revenue impact with radials in or radials out for each transmission owner. Ricky Bittle (Chair) asked that SPP Staff establish a work plan for the revenue impact analysis and report progress at the next RTWG meeting.

2 Regional Tariff Working Group May 6, 2004 Jim Stanton (Calpine) stated that at its April 27, 2004 meeting the SPP Board of Directors approved the Strategic Planning Committee s recommendations to conduct a coordinated cost-benefit study in lieu of each jurisdictional Member proceeding independently, and the sharing of the cost of this effort by all SPP Members. It approved the Independent Market Monitor Selection Task Force s recommendation to select Boston Pacific as SPP s Independent Market Monitor and directed SPP Staff to develop a contract for this service. It approved the MOPC s recommendation for changes to SPP Criterion 2. It approved all tariff modifications presented by the MOPC. It approved the slate of nominees for the Member s Committee. It approved the Finance Working Group s recommendation for a scope statement as the charter of the Finance Committee. It approved a resolution for Mr. Al Strecker in honor of his retirement. Jim Stanton (Calpine) stated that at the April 27, 2004 special meeting of members the SPP membership approved the modifications to Section 4.0 of the Bylaws that provide for transition to a non-stakeholder Board of Directors and elected the slate of nominees for the Members Committee presented by the Corporate Governance Committee. Agenda Item 5 Discussion of RTO Compliance Filing Pat Bourne (SPP) reported that SPP made a filing on Monday, May 3, in compliance with FERC s February 10, 2004 Order conditionally approving SPP s RTO proposal, subject to completion of certain additional steps. The filing addressed the completion of these steps and included all necessary associated tariff modifications. Agenda Item 6 Strategic Planning Committee (SPC) and Regional State Committee (RSC) Activities Update Ricky Bittle (Chair) reported that there were two major items in the minutes of the April 23 rd SPC meeting; a recommendation that SPP conduct the coordinated cost benefit study and a recommendation that SPP proceed with proposed Tariff changes and Independent Market Monitor Selection that are to be part of the compliance filing. Mike Proctor (MPSC) reported that the RSC has been formed and elected officers at its first meeting on April 26 th. The committee has also established a cost allocation working group. The RSC met by teleconference on May 5 th to discuss cost benefit study issues. Mike also announced that the RSC has a place on the SPP web site for the posting of committee materials and information. RSC information may be found by selecting Committees from the SPP home page and then selecting Regional State Committee. Agenda Item 7 Report on Mini-Participant Funding Symposium and Related Activities Bruce Rew (SPP) summarized the key issues that arose during the May 5 th symposium. During discussions it became clear that early RSC involvement in the development of the cost allocation plan was critical to successful completion. Issues related to the Base Plan Upgrade category included the precise meaning and implications of facility obsolescence and the manner by which new interconnections would be differentiated from facilities 2

3 Regional Tariff Working Group May 6, 2004 installed to accommodate load growth. Bruce noted that there was a diverse response to the allocation alternatives presented. Subsequent to Bruce s report, there was significant additional discussion regarding the upgrade categories, transmission rights that would be associated with funding and the handling of AC and DC merchant facilities. Agenda Item 8 Pending Tariff Filings at FERC Pat Bourne (SPP) summarized the filing status of each of the Board-approved Tariff changes. He reported that Staff conducted a pre-filing conference call with FERC Staff on Tuesday, May 4 th. The reason for the call was to discuss the purpose and mechanics of new Attachments Z and AA. Schedule 4-A was not discussed. Current plans call for the immediate filing of new Attachment AA with an effective date of July 1, 2004, with a view to implementation as soon as possible. The remaining changes are to be filed shortly thereafter. Agenda Item 9 Adjustments to Revenue Requirements and to System Loads for Determination of NITS Charges Dennis Reed (Westar Energy) discussed the problem with the current Tariff language and proposed remedy set out in the proposal memorandum to the RTWG (Attachment 3 Proposal) and in the proposed Tariff change language (Attachment 4 Tariff changes). Dennis Reed (Westar Energy) moved that the proposed Tariff language changes proposed be adopted. David Grover (Xcel Energy) seconded the motion. The motion carried with four abstentions. Agenda Item 10 Limitation of Liability Tariff Modifications In preparation for the meeting, Dennis Reed (Westar Energy) distributed a memorandum produced by Westar s FERC counsel regarding the limitation of liability clauses currently in the SPP Tariff (Attachment 5 Limitation of Liability Memorandum). His purpose was to bring attention to the subject and start discussion among RTWG members. The subject of the memorandum was discussed with no action taken. Agenda Item 11 Transmission Service Charge for Imbalance Energy Delivery On behalf of the Market Working Group (MWG), Gene Anderson (OMPA) sought initial RTWG discussion of a question that arose during MWG deliberations. The question posed to the RTWG is the following: Is it appropriate to charge a transmission fee for the delivery of imbalance energy to a customer taking transmission service only under the non-rate terms and conditions of the SPP Tariff? Opinions were expressed both in support of a charge and in support of no charge. There was also substantial discussion about what charge should be applied. At the end of the discussion Ricky Bittle (Chair) asked Gene to clarify the question. Gene agreed to distribute a clarification of the question. 3

4 Regional Tariff Working Group May 6, 2004 Agenda Item 12 Task Force Reports and Discussion of Issues Transmission Definition Task Force Based on the feedback provide by the MOPC discussed above, Pat Bourne (SPP) stated that SPP Staff would move forward with the revenue impact analysis of the radials inclusion/exclusion question, as previously discussed. VAR Compensation Task Force Chair Jim Stanton (Calpine) reported that the VCTF had scheduled a joint conference call on the subject with the Voltage and Reactive Management Task Force of the Operating Reliability Working Group. The purpose of the call is to discuss methods that might be employed to assess the need for reactive supply at specific locations on the transmission system. Formula Rates Task Force Chair Jay Toungate (AEP) reported that the task force needed to review the status of the project. RTWG members expressed significant interest in having access to the formulas to review for action to be taken at the next meeting. Ricky Bittle stated that it was important that action be taken soon in order to move the issue to the MOPC in time for its July meeting and that if that meant having an additional RTWG meeting on or before July 1, that would be done. Pat Bourne (SPP) stated that the ROE consultant was close to having a preliminary report of his findings and that he would obtain those initial results and check with Alan Heintz on the status of his work. Agenda Item 13 Review of Proposed Meeting Schedule The next meeting will be Thursday, June 10 th, at the DFW Airport Marriott in at 8:30 a.m. It was recognized that an additional meeting, on or before July 1 is likely to be necessary. Agenda Item 14 Adjournment Chair Ricky Bittle adjourned the meeting at 10:50 a.m. 4

5 Southwest Power Pool REGIONAL TARIFF WORKING GROUP May 6, 2004 AEP Offices Dallas, TX 8:30 a.m. 4:00 p.m. - A G E N D A - As Amended At The Meeting 1. Call to Order & Introductions, Receipt of Proxies 2. Review of Agenda and Additional Agenda Items 3. Approval of April 8, 2004 Minutes 4. OPC, Board and Members Meetings Reports 5. Discussion of RTO Compliance Filing 6. Strategic Planning Committee and RSC Activities Update 7. Report on Mini-Participant Funding Symposium and Related Activities 8. Pending Tariff Filings at FERC Attachment AA Service Schedule 4-A Attachment Z Attachment P 9. Adjustments to Revenue Requirements and to System Loads for Determination of NITS Charges 10. Limitation of Liability Tariff Modifications 11. Transmission Service Charge for Imbalance Energy Delivery 12. Task Force Reports and Discussion of Issues Transmission Definition Task Force Report Multi-Owner Compensation Task Force VAR Compensation Task Force Formula Rates Task Force 13. Review of Proposed Future Meeting Schedule 14. Adjournment

6 Southwest Power Pool REGIONAL TARIFF WORKING GROUP April 8, 2004 Dallas/ Ft. Worth Airport Hyatt Hotel 8:00 a.m. - 4:00 p.m. Agenda Item 1 Call to Order, Introductions and Receipt of Proxies Ricky Bittle (Chair) called the Regional Tariff Working Group (RTWG) meeting to order at 8:00 a.m. with a round of introductions. Other RTWG members in attendance were: Gene Anderson (OMPA), Bob Bowser (KEPCo), Bill Dowling (Midwest Energy), David Grover (Xcel Energy), Ron Kite (KCPL), Jim Sherwood (SWPA), Bary Warren (Empire), Pat Bourne (SPP), Robert Pennybaker for Dennis Bethel (AEP), David Brian (ETEX), Mark Foreman (TNSK), John Gunesch (OG&E), Dennis Reed (Westar Energy), Jim Stanton (Calpine), Mitch Williams (WFEC), Roy Sundman (SPP). Others in attendance included: Robert Shields (AECC); Carl Huslig (Aquila); David Kays (OG&E); Terri Gallup and Jay Toungate (AEP); Wes Berger (Xcel Energy) and Les Dillahunty and Bruce Rew (SPP). Those attending by phone include Pat Mosier (APSC), Tom DeBaun (KCC) and Gary Newell (City of Lafayette). Agenda Item 2 Review of Agenda and Additional Agenda Items The agenda was approved with the addition of a brief discussion of the working group roster (Agenda Attachment 1). Agenda Item 3 Approval of Minutes The minutes of the March 4, 2004 meeting were approved with the addition of Robert Shields (AECC) as having attended the meeting by phone (3/4/04 Minutes Attachment 2). Agenda Item 4 RTWG Roster Pat Bourne (SPP) announced that David Toole (Cargill Alliant) had been added to the working group and asked for participation by an additional interested member from the customer sector of the membership. The currently effective roster is attached (Regional Tariff Working Group Roster Attachment 3). Agenda Item 5 Strategic Planning Committee (SPC) and Regional State Committee (RSC) Activities Update Ricky Bittle (Chair) reported that the SPC had conducted a conference call earlier in the week, with significant discussion dedicated to the SPP Cost/Benefit analysis process. He stated that Richard Spring (SPC Chair) established a task force to make recommendations concerning how and by whom the analysis would be done and indicated that Richard expected that the analysis would be completed in approximately six months. Additionally, Ricky reported that the SPC discussed the APSC docket related to the participation of Entergy in the SPP RTO. He also reminded the group of the special meeting of the membership on April 27, to decide on the changes in the new bylaws that modify SPP governance, providing for a fully non-stakeholder board.

7 Regional Tariff Working Group April 8, 2004 Les Dillahunty (SPP) reported that the RSC has been active and understands that it is making progress. Although SPP Staff has not been involved in the calls, Les has learned that this group is discussing similar topics and has set up a task force to work on participant funding issues. Tom DeBaun (KCC) reported that he expected that the RSC will complete incorporation within a week and reminded the group that the RSC meetings were open. He indicated that the next meeting will be April 26. Agenda Item 6 Report on Participant Funding Symposium and FERC Technical Conference Les Dillahunty (SPP) walked the group through his written report (Report Attachment 4). He highlighted the White Paper Mini-symposium to be held on the afternoon of May 5 from 2:00 p.m. 5:00 p.m., right after the conclusion of the Market Working Group meeting at the AEP Center in Dallas, and the Participant Funding Symposium II, scheduled for June 9. With respect to the FERC White Paper Technical Conference, Les indicated that there was good discussion and concluded with a can-do attitude. States and members became re-engaged in the process and the FERC commissioners seemed pleased with the process. Agenda Item 7 RTO Order Compliance Tariff Modifications Pat Bourne (SPP Staff) introduced the opinion letter from Mike Small (Memorandum Attachment 5) and the draft modifications to Part IV of the Tariff, including addition of new Section 39 (Tariff modifications Attachment 6). These materials have been prepared to explain and specify that each Transmission Owner is subject to the non-rate terms and conditions of the Tariff in compliance with FERC s order in the SPP RTO proceeding. Pat also introduced the proposed modifications to Tariff Attachment O (Attachment O-Draft - Attachment 7), also developed in compliance with FERC s order in the SPP RTO proceeding. Pat stated that the Part IV revisions and modifications to Attachment O are before the RTWG for approval and recommendation to the OPC, and are necessary for the RTO compliance filing. After initial discussion on these Tariff modifications, Gene Anderson (OMPA) moved and David Grover (Xcel Energy) seconded a motion to approve the Part IV Tariff modifications. The motion was approved unanimously. Ricky introduced the proposed changes to Attachment O and Pat indicated that SPP s Transmission Working Group had reviewed and endorsed this draft of the modifications. Bary Warren (Empire) moved that the proposed changes to Attachment O be approved provided that the last sentence of Section 2.0 be modified to read and subject to review and/or approval as required by the FERC or State regulatory authorities where appropriate. Bill Dowling (Midwest Energy) seconded the motion. During discussion of the motion, Bary proposed to amend the motion to strike the words where appropriate from the sentence as proposed. The motion to amend failed for lack of a second. A straw vote on the primary motion resulted in 7 in favor of the motion and 6 against. Since the vote was close, Ricky sought additional discussion. After substantial discussion, a motion for reconsideration was made by Gene Anderson (OMPA) and seconded by Ron Kite (KCPL). The motion for reconsideration passed. Thereafter, Dennis Reed (Westar) moved that the modifications to Attachment O as originally proposed, without the additions proposed by Bary Warren (Empire), be approved. John Gunesch (OG&E) seconded the motion. This motion passed with 12 in favor and 1 opposed - Bary Warren (Empire). 2

8 Regional Tariff Working Group April 8, 2004 Agenda Item 8 BPWG Review of New Business Practice 1.10 On behalf of the Business Practices Working Group (BPWG), Lanny Nickell (SPP) presented the proposed new Business Practice 1.10 Real Time Discounting (1.10 Real-Time Discounting Attachment 8) for Tariff compliance assessment by the RTWG. Lanny summarized the purpose of the business practice, described its interaction with current non-firm service discounting policy and indicated that as conceived, the amount of any discount provided was to be left to SPP Staff to determine. Dennis Reed (Westar Energy) stated that the discounting policy associated with the business practice should be directed by SPP s Discounting Working Group (DWG). The RTWG concluded that there is no Tariff issue raised by the proposed business practice, but recommended that the BPWG obtain direction on the discounting process to be used from the DWG. Agenda Item 9 Compliance with Orders 2003 and 2003-A Including ER Pat Bourne (SPP) worked through the regulatory history associated with SPP s compliance with these FERC orders to date, and described the proposed next steps, both of which are set out on the Report on SPP Order 2003 Compliance (Order 2003 Compliance - Attachment 9). Pat indicated that he believed that the proposed compliance strategy is consistent with previous Board of Directors direction on the matter. Pat also stated that since the Order 2003-A LGIA template did not separate Transmission Provider and Transmission Owner responsibilities, an agreement in the form of the Agreement For the Allocation of Responsibilities With Regard To Large Generator Interconnection Procedures and Interconnection Agreement (Allocation Agreement - Attachment 10) would be implemented on a case-by-case basis. This form-of-agreement would also be included in the anticipated compliance filing. The RTWG concluded that the compliance strategy is reasonable. Agenda Item 10 Revision of Schedule 4-A OMPA Issues Pat Bourne (SPP) stated that the proposed revisions to previously proposed Schedule 4-A are being revisited at this time because SPP is considering filing the new schedule as a Section 205 modification to the SPP Tariff and withdrawing the version filed in ER Gene Anderson (OMPA) introduced the revisions that he proposed to Schedule 4-A: 1. a modification that clarifies that the schedule would only apply to transactions across Control Area boundaries; 2. a modification that provides a default basis for allocation of generation output among multiple schedules from a single generator where the generator operator fails to provide a timely basis for settlement; 3. a modification that sets a reasonableness standard for acceptance of other arrangements as alternatives to Schedule 4-A; and 4. a modification to establish a new pricing basis for charges under Schedule 4-A, replacing the use of the individual Transmission Owner s FERC approved Schedule 4 rates. Gene moved that the modifications he proposed be approved. Jim Stanton (Calpine) seconded the motion. Subsequent to discussion on the motion, Dennis Reed (Westar Energy) moved to amend the motion to reinsert the original language on charges and reject the modifications to the charges as proposed, but accept all other changes as Gene had proposed. John Gunesch (OG&E) seconded the motion. The motion to amend passed with 9 in favor and 5 opposed. The motion, as amended, passed with 12 in favor and 2 opposed. The service schedule, as approved, is attached (Schedule 4-A Attachment 11). 3

9 Regional Tariff Working Group April 8, 2004 Agenda Item 11 Transmission Service Prepayment Proposal Bruce Rew (SPP) summarized the provisions of the proposed new Tariff Attachment AA that provides customers the opportunity to prepay for transmission service, with such prepayment being made available to the Transmission Provider for system expansion. Subsequent to initial discussion of the proposed new Tariff attachment, Jim Stanton (Calpine) moved that the new attachment be approved as proposed. Dennis Reed (Westar Energy) seconded the motion. Thereupon Gene Anderson (OMPA) moved that the motion be amended to remove the words is requested in Section 2.0. The motion to amend failed due to lack of a second. The motion to approve, as submitted, passed with 12 in favor and 1 opposed. The proposed Tariff Attachment, as approved, is attached (Attachment AA Attachment 12). Agenda Item 12 Adjustments to Revenue Requirements and to System Loads for Determination of NITS Charges Dennis Reed (Westar Energy) described the problem with the current Tariff language and discussed an estimate of the revenue impact of the change in calculation method that he proposed. After discussion on the matter, Dennis agreed to redistribute the proposed Tariff changes and the rationale for them to the RTWG exploder. Agenda Item 13 Presentation of Wolverine and Florida Power and Light Orders Jeff Price (SPP) presented a summary and discussion of these two orders. Thereafter, he responded to questions and discussion of their content and importance to current issues was concluded. The presentation is attached (Analysis of the Wolverine and FP&L Orders Attachment 13). Agenda Item 14 Task Force Reports and Discussion of Issues Transmission Definition Task Force Chair Les Dillahunty (SPP) and chair of the task force stated that when the transmission facilities definition was last discussed, the RTWG wanted to defer action on it until after the initial Participant Funding Symposium. He then sought discussion on next steps. After discussion on the matter, Dennis Reed (Westar Energy) moved that the definition be approved using Option C of the proposal for the inclusion of radials. John Gunesch (OG&E) seconded the motion. The motion to adopt the definition, with the Option C provision for the inclusion of radials, was approved with 9 in favor and 3 opposed. The definition, as adopted, is attached (Transmission Facilities Definition Attachment 14). Multi-Owner Compensation Task Force Chair Bill Dowling (Midwest Energy) reported that the task force had been organized and its activities are expected to start with separate position presentations and responding concerns from parties on each side of the issue scheduled for late April and early May. Agenda item 13, the presentation of the Wolverine and Florida Power and Light orders, was requested by Bill and provided to support MOCTF activity. VAR Compensation Task Force Chair Jim Stanton (Calpine) summarized the key elements of his written report (VAR Compensation Task Force Report to Regional Tariff Working Group April 8, 2004 Attachment 15). Jim stated that Ron Ciesiel (SPP) is working with him on reliability issues and that the task force is also exploring 4

10 Regional Tariff Working Group April 8, 2004 generator compensation scaling, based on operational factors. Jim stated that information on the scaling issue was to be distributed to the task force shortly. Formula Rates Task Force Chair Jay Toungate (AEP) reported that the task force had conducted another conference call and developed a revised time frame for the annual formula rate review process that the task force recommends to the RTWG for approval (Formula Rate Review Process Attachment 16). After discussion of the proposal, Dennis Reed (Westar Energy) moved that the proposed time frame be approved. Bary Warren (Empire) seconded the motion. The motion passed on voice vote, with two opposed. Agenda Item 15 Review of Proposed Meeting Schedule The next meeting will be Thursday, May 6, at the AEP Center in Dallas starting at 8:30 a.m. The Participant Funding White Paper Mini-Symposium will also be held at the AEP Center on Wednesday, May 5 from 2:00 p.m. to 5:00 p.m., right after the conclusion of the MWG meeting. An additional meeting was tentatively scheduled for June 10 starting at 8:30 a.m. Agenda Item 16 Adjournment Chair Ricky Bittle adjourned the meeting at 1:55 p.m. 5

11 Southwest Power Pool REGIONAL TARIFF WORKING GROUP April 8, 2004 Dallas/ Ft. Worth Airport Hyatt Hotel 8:00 a.m. - 3:00 p.m. - A G E N D A - 1. Call to Order & Introductions, Receipt of Proxies 2. Review of Agenda and Additional Agenda Items 3. Approval of March 4, 2004 Minutes 4. RTWG Roster 5. Strategic Planning Committee and RSC Activities Update 6. Report on Participant Funding Symposium and FERC Technical Conference 7. RTO Order Compliance Tariff Modifications New Section 39 Applicability of Non-Rate Terms and Conditions Attachment O 8. Business Practices Working Group Real Time Discounting (Non-Firm Service) Business Practice 9. Compliance with Orders 2003 and 2003-A Including ER Revision of Schedule 4-A OMPA Issues 11. Transmission Service Prepayment Proposal 12. Adjustments to Revenue Requirements and to System Loads for Determination of NITS Charges 13. Presentation of Wolverine and Florida Power and Light Orders 14. Task Force Reports and Discussion of Issues Transmission Definition Task Force Report Multi-Owner Compensation Task Force VAR Compensation Task Force Formula Rates Task Force Generation Interconnection Agreement Task Force 15. Review of Proposed Future Meeting Schedule 16. Adjournment

12 Southwest Power Pool REGIONAL TARIFF WORKING GROUP March 4, 2004 Dallas/ Ft. Worth Airport Hyatt Hotel 9:30 a.m. - 4:00 p.m. Agenda Item 1 Call to Order, Introductions and Receipt of Proxies Ricky Bittle (Chair) called the Regional Tariff Working Group (RTWG) meeting to order at 9:30 a.m. with a round of introductions. Other RTWG members in attendance were: Gene Anderson (OMPA), Robert Pennybaker for Dennis Bethel (AEP), David Brian (ETEX), Bill Dowling (Midwest Energy), David Grover (Xcel Energy), John Gunesch (OG&E), Ron Kite (KCPL), Dennis Reed (Westar Energy) Jim Sherwood (SWPA), Jim Stanton (Calpine), Bary Warren (Empire), Mitch Williams (WFEC), Pat Bourne (SPP), Roy Sundman (SPP). Others in attendance included: Mark MacDonald (CLECO Power); Alan Derichsweiler (WFEC); David Kays and Jim McAvoy (OG&E); Shah Hossain (Westar Marketing); Richard Ross, Terri Gallup and Jay Toungate (AEP); Wes Berger (Xcel Energy) and Les Dillahunty and Bruce Rew (SPP). Those attending by phone include Tom DeBaun (KCC), Tim Hostetler and Bob Tumilty (AEP) and Robert Shields (AECC). Agenda Item 2 Review of Agenda and Additional Agenda Items The agenda was approved as proposed (Attachment 1 Agenda). Agenda Item 3 Approval of Minutes The minutes of the February 5, 2004 meeting were approved (Attachment 2 2/5/04 Minutes). Agenda Item 4 RTO Order: Content Discussion and Tariff Issues Pat Bourne (SPP) reviewed the general content of the February 10 order, highlighting the conditions to be met for RTO recognition. He focused attention on the importance of the Tariff changes that will be necessary, including modifications to Attachment O and recognition of the cost of customerowned transmission facilities. Pat reviewed an initial draft of modifications to Attachment O (Attachment 3 Attachment O) and explained the rationale for the changes. He indicated that a revised Attachment O will be filed with SPP s compliance filing. Thereafter, the proposed modifications were discussed, with no action taken. Ricky Bittle (Chair) stated that he is organizing a task force to consider the issue of compensation for customer-owned transmission facilities as raised by Lafayette in its protest. The task force will be chaired by Bill Dowling (MWE) and that a recommendation on the issue will be required from the RTWG by the end of the year. Bill indicated that it will be essential that a representative from both CLECO and the City of Lafayette be on the task force to bring its work to successful conclusion. Ricky asked that anyone interested in participating on the task force contact himself or SPP Staff, so that the task force might be organized as soon as possible.

13 Regional Tariff Working Group March 4, 2004 Agenda Item 5 Strategic Planning Committee and RSC Activities Update Ricky Bittle (Chair) indicated that the SPC had discussed proposed changes in the bylaws necessary to comply with the RTO order, and stated that proposed changes will be published shortly. He also reported that the SPC has recommended that the fully independent board be seated as soon as possible. Les Dillahunty (SPP) reported that member representatives and SPP Staff had been in contact with Oklahoma and Arkansas state commission representatives and that other actions related to state commission involvement are underway. Agenda Item 6 BPWG Review of Business Practices On behalf of the Business Practices Working Group (BPWG), Lanny Nickell (SPP) presented two proposed business practice changes for Tariff compliance assessment by the RTWG. First, Business Practice 2.10 has been modified to permit a minimum network resource designation period of one day. Additionally, the BPWG has developed an application form to be used by the customer to designate new network resources. After extensive discussion and suggested modifications, the RTWG determined that Business Practice 2.10, as modified, conforms with all relevant provisions of the Tariff. Second, Business Practice 3.5 has been modified to clarify the application of rollover provisions to long-term requests that have profiled capacity quantities. After discussion of the modifications and a suggested language change, the RTWG determined that Business Practice 3.5, as modified, conforms with all relevant provisions of the Tariff. Lanny also indicated that the Operations Reliability Working Group (ORWG) needs an RTWG member to serve on the Control Area Consolidation Task Force that the ORWG has established. Agenda Item 7 Revision of Schedule 4-A OMPA Issues Gene Anderson (OMPA) introduced revisions that he proposed to Schedule 4-A, including a specification of pricing at incremental cost plus 10% and the use of a +/- 1.5% dead band (Attachment 4 - Mark-up of Proposed Changes). The proposed changes were discussed with no action taken. Agenda Item 8 Transmission Service Prepayment Proposal Bruce Rew (SPP) presented a proposed new Tariff Attachment AA that provides customers the opportunity to prepay for transmission service, with such prepayment being made available to the Transmission Provider for system expansion (Attachment 5 Proposed Attachment AA) (Attachment 6 Explanatory Presentation). The proposed new attachment was discussed with no action taken. Agenda Item 9 Delivery Point Metering Costs Gene Anderson (OMPA) introduced a memorandum addressed to the RTWG from Bob Bowser (KEPCo), David Brian (ETEX) and himself, regarding the assignment of delivery point metering costs (Attachment 7 Memorandum). Gene suggested that this issue might be properly allocated to the task force considering compensation for customer owned transmission facilities. Ricky assigned the issue to the task force. Agenda Item 10 Network Service Tariff Modification Denis Reed (Westar) indicated that he had not had an opportunity to complete the additional analysis necessary to conclude a recommendation on this issue. He asked that the issue be deferred. 2

14 Regional Tariff Working Group March 4, 2004 Agenda Item 11 Participant Funding Symposium Discussion Les Dillahunty (SPP) introduced the proposed agenda for the symposium (Attachment 8 Symposium Agenda). Several modifications were suggested and discussed. Les reported that he expected the agenda for the FERC Technical Conference to be published soon. Agenda Item 12 Task Force Reports and Discussion of Issues Queuing Improvement Task Force Ricky Bittle (Chair) called the question regarding approval of the new Tariff Attachment Z and related base Tariff modifications necessary to accommodate it (Attachment 9 Tariff Attachment Z) (Attachment 10 Related Base Tariff Modifications). Jim Stanton (Calpine) moved that the new attachment and related Tariff modifications be approved. Mitch Williams (WFEC) seconded the motion. After extensive discussion the proposed modifications were approved with opposition indicated by Gene Anderson (OMPA), David Brian (ETEX) and Ricky Bittle (AECC). VAR Compensation Task Force Chair Jim Stanton (Calpine) reported that he had distributed a proposed Schedule 2 to the Task Force and that a template for calculation of reactive charges using the AEP Method will soon be distributed to reactive power providers on the SPP system to obtain an estimate of charges using this single methodology. Jim indicated that the compensation process anticipates all load being placed under the SPP Tariff. Jim also stated that he would distribute the proposed Schedule 2 draft to the entire RTWG for review. Formula Rates Task Force Subsequent to further discussion of the proposed annual rate review process, included as Attachment 9, Chair Jay Toungate (AEP) reported that he would call another teleconference of the Task Force and open the call to participation by any RTWG member. The purpose of the call is to develop a final review process proposal for presentation to the RTWG at the April 8 meeting. Agenda Item 12 Review of Proposed Meeting Schedule The next meeting will be Thursday, April 8, in Dallas. An additional meeting was tentatively scheduled for May 6. Agenda Item 13 Adjournment Chair Ricky Bittle adjourned the meeting at 2:00 p.m. 3

15 Regional Tariff Working Group Company Representative Telephone AEP-West Mr. Dennis Bethel, Member (TO) (614) Arkansas Electric Cooperative Corp. Mr. Ricky Bittle, Chair (TC) (501) Calpine Energy Services Mr. James Stanton, Member (TC) (713) Cargill - Alliant, LLC Mr. David Toole, Member (TC) (952) Coral Power Trading Mr. Jeff Brown, Member (TC) (713) Empire District Electric Co. Mr. Bary Warren, Member (TO) (417) East Texas Electric Cooperative Mr. David Brian, Member (TC) (770) Kansas City Power & Light Mr. Ron Kite, Member (TO) (816) Kansas Electric Power Cooperative Mr. Robert D. Bowser, Member (TC) (785) Westar Energy Mr. Dennis Reed, Vice-Chair (TO) (785) Midwest Energy Mr. Bill Dowling, Member (TO) (785) Missouri Public Service Commission Mr. Mike Proctor, Member (573) OG+E Electric Services Mr. John Gunesch Jr., Member (TO) (405) Oklahoma Municipal Power Mr. Gene Anderson, Member (TC) (405) Southwest Power Pool Mr. Pat Bourne, Secretary (501) Southwestern Power Administration Mr. James Sherwood, Member (TO) (918) Southwestern Public Service Co. Mr. David Grover, Member (TO) (612) Tenaska Power Services Co. Mr. Mark Foreman, Member (TC) (817) Western Farmers Electric Mr. Mitchell Williams, Member (TO) (405)

16 I. Participant Funding Symposium A. Policy or conceptual discussion 1. Background material 2. Presentations: Rolled-in advocate Participant funding advocate Scenarios of specific funding issues B. Discussion Questions (straw votes) Participant Rolled-in Funded 2. Should focus be on: a. new upgrades only (favored slightly) b. new upgrades and assignment of FTR s for existing facilities. 3. Participants favored a bright line option with some type of response factor (not just voltage) over applying a cost/benefit study to each upgrade request. 4. Transmission Definitions: a. Radials out 15 votes b. Radials in 24 votes c. Radials with two or more customers 16 votes (Observation/ indicates 40 of 55 votes favored the inclusion of radials.) 5. Agreement to include merchant and capital investment options. 6. Implementation within five years C. SPP has retained Barker, Dunn & Rossi to provide background support with the participant funding project. D. RSC has formed a Participant Funding Task Force. E. May 5: White Paper Mini-symposium: AEP Center, Dallas (MWG, RTWG) June 9: Participant Funding Symposium II, Dallas Airport Marriott (Transmission Planning Summit) F. White Paper Outline 1. Who Ownership, funding incentives Traditional TO only Traditional TO with incentives Provision of capital Merchant investment DSM, generation

17 2. How - Focus Future transmission upgrades only Future transmission upgrades as well as FTR allocations for existing facilities Bright line (response factor other than voltage) Cost benefit study 3. When Implementation 4. Where Assignment of Cost Spectrum from rolled-in to participant funded Zone, zone-plus, region Reliability and economic upgrade definitions Requested upgrades 5. Others Ameren/Missouri/MISO Service Agreement Other impacts GIA, markets, planning Decision trees (example) FERC WHITE PAPER TECHNICAL CONFERENCE A. Participants: all FERC commissioners, Denise Bode Oklahoma, Irma Muse Dixon, Louisiana, Sandra Hochstetter and Randy Bynum - Arkansas, David King New Mexico, Julie Parsley Texas, staff from other footprint states except Mississippi. (Panelists 11) B. Panelists and states had an opportunity to raise issues important to them. A number of comments were included in their individual requests for rehearing, clarification, etc., filed with the FERC. C. Panelists were asked by Chairman Wood, From your company s perspective, is this RTO plan from Southwest Power Pool good for you and the region? All responded yes. The states were asked basically the same question with the same response. D. Generally a positive response. Can do attitude; states and members re-engaged.

18 March 9, 2004 MEMORANDUM TO: Nick Brown FROM: Michael E. Small You asked us to address aspects of the issue of Southwest Power Pool, Inc. ( SPP ) subjecting bundled loads to the non-rate provisions of its open access transmission tariff ( OATT ), as required by the Federal Energy Regulatory Commission s ( FERC or Commission ) recent order granting SPP regional transmission organization ( RTO ) status. Southwest Power Pool, Inc., 106 FERC 61,110 (2004)( SPP RTO Order ). First, the Commission s requirement on this was not a surprise given its past similar requirements involving other RTO s/iso s. Other RTO s/iso s have implemented agreements and tariff provisions which put transmission owners bundled loads under a regional tariff and at a minimum subject such loads to the non-rate terms and conditions of the tariff. Second, as to exactly how this requirement is to be implemented, there is some guidance but we cannot provide a definitive statement on this issue. In the attached tariff provisions, we submit our initial take on what is meant by this requirement for all bundled loads to be subject to the nonrate terms and conditions of the tariff (though ultimately FERC may add or delete certain of the provisions as in our initial research we could find no clear template to follow). The Commission made clear in its review of SPP s RTO proposal that bundled and grandfathered loads must be subject to the non-rate terms and conditions of the SPP OATT. The Commission stated, Consistent with Order No requirements, we will require that TOs [transmission owners], on behalf of their entire load including grandfathered wholesale and bundled retail loads, take service under the non-rate terms and conditions in the SPP OATT as a prerequisite to obtaining RTO status from the Commission. SPP RTO Order at P 108. The Commission further explained that under a functioning SPP RTO, the SPP transmission owners will no longer be the transmission providers. Id. at P 109. The Commission s decision regarding the SPP RTO is consistent with its decisions regarding the applicability of the Midwest ISO OATT though, curiously, it is more narrowly stated than in the applicable Midwest ISO Order. In Opinion No. 453, the Commission directed the Midwest ISO to revise its Midwest ISO Agreement and Tariff, as necessary, to place and provide all load under the Midwest ISO s Tariff. Midwest Indep. Transmission Sys. Operator, Inc., Opinion No. 453, 97 FERC 61,033 (2001), order on reh'g, Opinion No. 453-A, 98 FERC 61,141 (2002), order on remand, 102 FERC 61,192, order denying reh'g, 104 FERC 61,012 (2003), appeal pending, Midwest ISO Transmission Owners v. FERC, U.S. Court of Appeals, D.C. Cir. Case No In Opinion No. 453-A, the Commission emphasized that its

19 objective in directing that all load be placed under the Midwest ISO OATT was to work toward the goal set forth in Order No that the RTO be the sole provider of transmission service over facilities under its control. Based on the requirements of Order No. 453, the Midwest ISO filed revisions to its OATT providing that all load will be subject to the non-rate terms and conditions of the OATT (though the Midwest ISO did not attempt to define this in its tariff). The tariff provisions also avoided subjecting bundled load to various charges that already were reflected in retail rates subject to state jurisdiction such as transmission charges. In submitting that filing, the Midwest ISO did not await state commission approvals. The Midwest ISO took it upon itself to submit tariff revisions in compliance. Those revisions were accepted by the Commission. See Midwest Indep. Transmission Sys. Operator, Inc., 101 FERC 61,113 (2002); Midwest Indep. Transmission Sys. Operator, Inc., 103 FERC 61,038 (2003); Midwest Indep. Transmission Sys. Operator, Inc., Letter Order, Docket No. ER (June 17, 2003). 1 As a result, of those tariff changes, we understand that all of the vertically integrated transmission owners at that time chose to become network customers under the Midwest ISO OATT within a relatively short period of time (largely due to the cost savings associated with taking network service as they would no longer need to pay for point to point service). We are not aware of the transmission owners seeking state approvals before moving ahead with the execution of network service agreements, though we have not thoroughly researched this issue as of this time. The Commission s directive is also consistent with the procedure for existing contracts or bundled load for transmission owners in other regional organizations. We understand that the transmission owners in both PJM and NEPOOL that are load serving entities are network customers under both of those tariffs for all of their loads. In the NEPOOL tariff, all customers with load in the NEPOOL Control Area who do not take Internal Point to Point Service at all of its Points of Delivery are required to take and pay for Regional Network Service. In the case of PJM, each of the transmission owners takes network service. In Atlantic City Elec. Co., 85 FERC 61, 445, at 62,663 (1998), FERC accepted the network service agreement filed in compliance with a prior FERC order as making clear that the transmission owners will be obtaining transmission services from each other and from their own systems under the PJM Tariff. In an earlier order, FERC accepted a proposal by the PJM transmission owners to subject themselves to the non-rate terms and conditions of the PJM OATT, pay congestion costs, receive congestion revenues, and pay the scheduling and dispatching charges. As part of that proposal, the transmission owners also sought (and were allowed by FERC) not to 1 Subsequent to the issuance of Opinion Nos. 453 and 453-A, the United States Supreme Court issued a decision specifically addressing the Commission s jurisdiction over transmission, in the context of Order No The Supreme Court pointed out that, while the Commission s jurisdiction over the sale of power is confined to the wholesale market, the Commission s jurisdiction over electricity transmissions is not subject to such a limitation. New York v. FERC, 535 U.S. 1, at 20 (2002). The Supreme Court reasoned that [b]ecause the FPA [Federal Power Act] authorizes FERC s jurisdiction over interstate transmissions, without regard to whether the transmissions are sold to a reseller or directly to a consumer, FERC s exercise of this power is valid. Id. 2

20 pay the network service charges because of the transmission owners view that the payment of such charges for bundled load would infringe on state jurisdiction (thus, suggesting that their proposal to subject themselves to the non-rate terms and conditions would not infringe on state jurisdiction). In that order, the Commission also made clear that the transmission owners had the right to choose whether to take point-to-point or network transmission service. PJM, 81 FERC 61,257 (1997). Of note is that we were informed by PJM s counsel that he was not aware of the PJM Companies seeking state approvals before entering into the network agreements which did not require payment of network service charges but otherwise subjected the transmission owners to the terms of the PJM OATT. You also questioned whether the Commission s reference to non-rate terms and conditions provides enough direction as what SPP s compliance filing should cover. The phrase non-rate terms and conditions has been used by the Commission and Administrative Law Judges ( ALJ ) and is broadly defined as simply those terms and conditions that do not prescribe the rate for service under the OATT. For example, in an initial decision regarding nonrate terms and conditions, an ALJ defined non-rate terms and conditions as including, but not being limited to definitions, obligations to interconnect or construct transmission expansions and facility upgrades, expansion processes, interconnection processes, creditworthiness requirements, dispute procedures, along with other miscellaneous tariff provisions. Pac. Gas & Elec. Co., 88 FERC 63,007, at 65,044 (1999). The Commission has also described non-rate terms and conditions as including rollover rights, operating requirements, deposits, and determination of network load. See Maine Pub. Serv. Co., 90 FERC 61,234 (2000). As noted above, we have attempted to detail our best take on what is meant by the term in the attached tariff provisions. We would add that, in part, under FERC policy even before the order, transmission owners should have expected to have to comply with some of the major parts of the non-rate terms and conditions. FERC, for example, expected that transmission owners serving loads designate network resources and loads even without taking network service under their own tariffs. 2 FERC also has required that curtailments of transmission also involve curtailments of comparable bundled load service. 3 K:\SPP\SPPopinionletter1.doc 2 See Aquila Power Corp. v. Entergy Servs., Inc., 101 FERC 61,328, at P 11 (2002)( even for reservations of capacity for bundled retail native load customers, a utility is required to designate specific resources and load associated with these reservations. ); Aquila Power Corp. v. Entergy Servs., Inc., 90 FERC 61,260, at 61,859 (2000). 3 See N. Am. Elec. Reliability Council, 96 FERC 61,079, at 61,345 (2001)( The Commission continues to believe that it has authority to require public utilities to treat customers using unbundled wholesale interstate transmission services in a manner that is comparable to the treatment of customers using bundled retail interstate transmission services, and thereby to prevent discrimination against unbundled users of the interstate transmission system. 3

21 Southwest Power Pool Original Sheet No. 92 FERC Electric Tariff Fourth Revised Volume No. 1 DRAFT 3/8/04 IV. SPECIAL RULES ON USE OF TARIFF 37. During Transition Period 37.1 Service Not Required for Bundled Customers or Customers Under Retail Access Programs: A Transmission Owner shall not be obligated to take Network Integration Transmission Service or Point-to-Point Transmission Service from the Transmission Provider in accordance with this Tariff for (1) bundled retail load not having a choice of power suppliers or (2) for bundled retail load it continues to serve that had the right to choose a different power supplier under a state retail access program or legislation and that was retail load served by the Transmission Owner prior to the retail load receiving the right to choose a different supplier Availability of Network Integration Transmission Service: All Transmission Owners shall have the option of electing Network Integration Transmission Service for retail loads or customers whether or not such loads or customers have the right to choose a different power supplier during the Transition Period Unbundled Wholesale: A Transmission Owner shall be obligated to take Network Integration Transmission Service or Point-to-Point Transmission Service from the Transmission Provider in accordance with this Tariff for any sales to wholesale load the Commission requires to be unbundled unless such service is arranged by another entity or is pursuant to a Grandfathered Agreement Grandfathered Transactions: During the Transition Period, transmission provided pursuant to Grandfathered Agreements shall continue to term in accordance with the provisions of the Grandfathered Agreement rather than under this Tariff unless the

22 Southwest Power Pool Original Sheet No. 92 FERC Electric Tariff Fourth Revised Volume No. 1 DRAFT 3/8/04 parties agree otherwise. Grandfathered Transactions are defined in Section 1.14a.

23 Southwest Power Pool Original Sheet No. 93 FERC Electric Tariff Fourth Revised Volume No After Transition Period 38.1 Applicability to Retail Load Having Choice: Beginning on the first day after the end of the Transition Period, this Tariff shall be applicable to all transmission service over the Transmission System provided for retail loads having the right to choose a different power supplier except for deliveries made pursuant to Grandfathered Agreements Applicability to Retail Load Not Having Choice: Beginning at the end of the fifth year after the last day of the Transition Period, the Transmission Owner shall take Network Integration Transmission Service or Point-To-Point Transmission Service from the Transmission Provider in accordance with this Tariff for sales to retail customers not having the right to choose a different power supplier Grandfathered Agreements: Transmission Service provided pursuant to Grandfathered Agreements shall continue to term in accordance with the provisions of the Grandfathered Agreements rather than under this Tariff unless the parties agree otherwise. Grandfathered Agreements are defined in Section 1.14a. 39. Applicability of Non-Rate Terms and Conditions 39.1 Bundled Retail and Grandfathered Load: Notwithstanding Sections 37 and 38 of this Tariff, Each Transmission Owner (which is not otherwise taking Network Integration Transmission Service ) is subject to the non-rate terms and conditions of this Tariff for: (1) its bundled retail load not having a choice of power suppliers; (2) its bundled retail load that had the right to choose a different power supplier under a state retail access program or legislation and that was retail load served by the

24 Southwest Power Pool Original Sheet No. 93 FERC Electric Tariff Fourth Revised Volume No. 1 Transmission Owner prior to the retail load receiving the right to choose a different supplier; and (3) its bundled load under Grandfathered Agreements. For purposes of this provision the non-rate terms and conditions are those that would apply to Network Customers except for (1) Section 28 other than the provision in Section 28.1 requiring Ancillary Services pursuant to Section 3 and Section 28.2; (2) Section 29 other than Sections 29.3 and 29.4; and (3) Sections 34.1, 34.2 and [Note-As this eliminates the need to sign a service agreement, need to ensure that TOs are otherwise obligated to abide by these terms.] In addition, unless a Transmission Owner executes a Service Agreement under this Part III, it will not be considered as taking Network Integration Transmission Service.

25 Southwest Power Pool Original Sheet No. 93 FERC Electric Tariff Fourth Revised Volume No. 1

26 DraftDRAFT March 3, ATTACHMENT O COORDINATED TRANSMISSION PLANNING AND EXPANSION PROCEDURES The highly interconnected nature of the Transmission System, and the associated high degree of interdependence of the facilities of the Transmission Owners, requires coordination of transmission planning efforts. These Procedures describecoordination requirements for transmission planning within the SPP Region.and expansion procedures for the SPP Transmission System. Transmission Owners are obligated to build facilities subject to regulatory approval under the provisions of this Tariff. The Transmission Provider will not build or own transmission facilities. These procedures neither obligate the Transmission Provider nor Transmission Owners to build or own facilities within another Transmission Owner s area where a limit may exist. Transmission Owners may at any time voluntarily form associations and partnerships between Members or with non- Members to jointly construct and finance new transmission facilities provided such projects are subject to the assessment process of these Procedures. 1.0 Planning Criteria The individual planning criteria of each Transmission Owner shall be the basis for determining whether a violation of criteria exists and when a need for new facilities should be considered. This planning criteria shall, at a minimum, conform to SPP Criteria and NERC Planning Standards. Transmission Owners shall submit their transmission planning criteria to the Transmission Provider. This criteria may be

27 DraftDRAFT March 3, modified at any time provided that, if the criteria is made more stringent, the increased requirements shall not apply retroactively to transmission planning studies previously completed nor studies already underway by SPP sthe Transmission Assessment Working Group (TAWG).Provider. 2.0 Planning and Assessment Studies The Transmission Provider shall independently perform regional transmission planning studies. These studies shall assess the reliability and economic operation of the SPP Transmission System. Transmission planning studies shallmay also be performed by individual Transmission Owners. Members shall contact the TAWGTransmission Provider whenever new facilities that impact interconnected operation are in the conceptual planning stage so that the optimal integration of any new facilities and potentially benefiting parties can be identified. The Transmission Provider s operating personnel shall periodically inform the TAWGTransmission Owners of identified operating constraints that should be addressed in future studies. Seasonal transmission assessments shall be performed by the TAWG.Transmission Provider. These planning studies and seasonal assessments are for purposes of identifying any planning criteria violations that may exist. Transmission Owners shall submit their five-year transmission construction plans to the Transmission Provider. The initial plans, existing as of January 1, 1999, shall be considered grandfathered and shall not be subject to review or approval by the TAWG.

28 DraftDRAFT March 3, In the event the assessment process identifies a violation, the violation shall be directed to the associated Transmission Owner. The responsible Transmission Owner shall respond by explaining why the violation is not valid or by identifying alterations in its transmission plan which correct the criteria violation. The Transmission Owner with an identified limit shall be responsible for performing studies to determine alternatives that remove the limit. If corrective action causes regional impacts and is therefore subject to cost sharing, the Transmission Provider s Staff shall participate in these studies if requested by the Transmission Owner or another Member. Recommendations developed by the responsible Transmission Owner to mitigate an identified violation shall be presented for review and approval by the TAWG.Transmission Provider. This review shall evaluate study results for negative impacts on the transmission systems of other Members. If such negative impacts are found, the TAWG,Transmission Provider, the impacted Member and the Transmission Owner shall participate in a joint effort to modify the recommendation to the satisfaction of all involved Members. If negative impacts are not found, the TAWGTransmission Provider shall accept the recommendation. If the TAWGTransmission Provider finds the study incomplete, the Transmission Owner shall make further analysis to the satisfaction of the TAWG.Transmission Provider. Once the recommendation is shown to address the violation and any negative impacts have been mitigated to the extent practicable, the TAWGTransmission Provider shall accept the recommendation. The Transmission Provider shall independently make the final determination in the process, subject to the

29 DraftDRAFT March 3, Dispute Resolution Procedures and subject to review by the FERC or state regulatory authorities where appropriate. 3.0 Need for New Facilities Undue limitation on the maintenance of the Transmission System and the provision of firm transmission service shall be deemed to create a need for new or upgraded facilities. Either situation shall require submittal of a transmission plan for review by the TAWGTransmission Provider to resolve the issue and may result in cost sharing among the entities that benefit from facility additions or improvements. This review can be initiated by any Member requesting firm transmission service under any applicable tariff. This review can also be initiated by any SPP organizational group as a result of its performance of operational assessments. If the Transmission Owner with an identified limit is unable to determine alternatives in a timely manner, the TAWGTransmission Provider may establish a task force to determine appropriate options and make a recommendation. Such task force roster shall include representation from the Member with the limiting facility and Members with transmission service or facilities that might be affected by the limiting facility or corrections. The task force shall provide a recommendation, along with options considered to the TAWGTransmission Provider for a review of impacts. Based on its review of the task force recommendations, the TAWGTransmission Provider shall

30 DraftDRAFT March 3, independently prepare a proposal for consideration by the SPP Board of Directors to direct the appropriate Transmission Owners to begin implementation of the project. 4.0 Construction a. Each Transmission Owner shall use due diligence to construct transmission facilities as directed by the SPP Board of Directors subject to such siting, permitting, and environmental constraints as may be imposed by state, local and federal laws and regulations, and subject to the receipt of any necessary federal or state regulatory approvals. Such construction shall be performed in accordance with Good Utility Practice, applicable SPP Criteria, industry standards, each Transmission Owner s specific reliability requirements and operating guidelines (to the extent these are not inconsistent with other requirements), and in accordance with all applicable requirements of federal or state regulatory authorities. Each Transmission Owner shall be fully compensated to the greatest extent permitted by The Commission, for the costs of construction undertaken by such Transmission Owner in accordance with this Tariff. b. After a new transmission project has been approved, the Transmission Provider will direct the appropriate Transmission Owners to begin implementation of the project. If the project forms a connection between facilities of a single Transmission Owner, that Owner will be designated to provide the new facilities. If the project forms a connection between facilities owned by two different Transmission Owners or between a new facility and the facilities of a Transmission Owner, both entities will be designated to provide the new facilities. The two entities will agree between themselves how much of the project

31 DraftDRAFT March 3, will be provided by each entity. If agreement cannot be reached, the Transmission Provider will facilitate the ownership determination process. c. A designated provider for a project can elect to arrange for another entity or another existing Transmission Owner to build and/or own the project in their place. If a designated provider or providers do not or cannot agree to implement the project in a timely manner, the Transmission Provider will solicit and evaluate proposals for the project from other entities and select a replacement designated provider.

32 REAL-TIME DISCOUNTING Business Practice During real-time or anticipated near-term conditions of heavy loading on an SPP constraint, SPP may offer discounts on non-firm point-to-point transmission service requested during the period of expected heavy loading. Such discounts will be offered for new service that has an unloading effect on the constraint. The following procedures shall be followed when these discounts are offered and taken. When a TLR level 1 or higher is called on an SPP constraint, SPP will post on the OASIS a notice of the discount, the period for which the discount is effective, and the source/sink combinations for which the discount will apply. After the notice is posted, the transmission customer must request and be granted non-firm point-to-point transmission service with an applicable source/sink combination and a start and stop time within the effective period of the discount. The customer must submit the transmission request using a service type that contains the subclass Discounted.

33 Report on SPP Order 2003 Compliance FERC, in Order No. 2003, Standardization of Generator Interconnection Agreements and Procedures, required amendment of open access transmission tariffs to include a pro forma Large Generator Interconnection Agreement ( LGIA ) and Large Generator Interconnection Procedures ( LGIP ), both applicable to Generating Facilities that exceed 20 megawatts. On January 20, 2004, SPP submitted a compliance filing proposing revisions to the SPP Tariff, to add a pro forma LGIA and LGIP, intended to implement Order No This filing was docketed as ER On February 10, 2004, FERC issued an order granting SPP RTO status, subject to its fulfillment of certain requirements that included meeting FERC s independence and governance standards. On March 5, 2004 FERC issued Order 2003-A, an Order on Rehearing of Order The effective date of Order 2003-A is April 26, This order further modified the pro forma LGIP and LGIA order by FERC in Order On March 19, 2004, FERC issued an order in ER accepting SPP s Order No Compliance Filing subject to a 5 month suspension, to become effective August 21, 2004, or upon an earlier date as may be specified by FERC, and required SPP to adopt the pro forma LGIA and LGIP set forth in Order No In this Order FERC found that, although FERC expects SPP to become independent in the near future, SPP is not a recognized RTO and does not yet meet the independence requirements of Order 200. Therefore, SPP is required to make a

34 ministerial filing adopting the default LGIA and LGIP required of non-independent transmission providers under Order This compliance filing is due on or before April 19, FERC recognized in the order in ER that the pro forma LGIA and LGIP set forth in Order No do not allocate responsibilities between transmission owners and transmission providers for the provision of Interconnection Service and suggested that SPP and the SPP Transmission Owners enter into an agreement to allocate those functional responsibilities under the LGIA. Although the SPP filing made in ER addressed this issue and the issue is clearly recognized in Order 2003-A, the order in ER requires the use of a supplemental agreement between SPP and the transmission owners to address this issue. As a non-independent transmission provider as concluded to date in ER , SPP must also accept the default provisions of 2003-A which become effective on April 26, SPP currently plans to make a compliance filing as required in ER by April 19, 2004 responding to both the Order in ER and Order 2003-A. Thus the default provisions of Orders 2003 and Order 2003-A will remain in effect for SPP until FERC takes action on the filing in ER

35 AGREEMENT FOR THE ALLOCATION OF RESPONSIBILITIES WITH REGARD TO LARGE GENERATOR INTERCONNECTION PROCEDURES AND INTERCONNECTION AGREEMENT This Agreement for the Allocation of Responsibilities With Regard to Large Generator Interconnection Procedures and Interconnection Agreement ( Agreement ), dated April, 2004, is entered into between Southwest Power Pool, Inc. ( SPP or Transmission Provider ) and the Transmission-Owning Members of SPP ( Transmission Owners ) that have executed this Agreement. SPP and the Transmission Owners are jointly referred to as the Parties and individually, as a Party. BACKGROUND WHEREAS, SPP administers the provision of open access transmission service as Transmission Provider under the terms and conditions of the SPP Open Access Transmission Tariff ( SPP Tariff ) on file with the FERC; WHEREAS, SPP has applied for, and conditionally received, approval from the Federal Energy Regulatory Commission ( Commission or FERC ) to function as a Regional Transmission Organization ( RTO ); WHEREAS, the FERC, in Order No. 2003, Standardization of Generator Interconnection Agreements and Procedures, FERC Stats. & Regs. 31,146 (2003), order on reh g, Order No A, 106 FERC 61,220 (2004), required amendment of open access transmission tariffs to include Large Generator Interconnection Procedures ( LGIP ) and a pro forma Large Generator Interconnection Agreement ( LGIA ), both applicable to Generating Facilities that exceed 20 megawatts;

36 WHEREAS, on January 20, 2004, SPP submitted revisions to the SPP Tariff, including LGIP and a pro forma LGIA, intended to implement Order No ( Order No Compliance Filing ); WHEREAS, on March 19, 2004, the FERC accepted SPP s Order No Compliance Filing subject to suspension, to become effective August 21, 2004, or upon an earlier date as may be specified by the FERC, and required SPP to adopt the LGIP and pro forma LGIA set forth in Order No (Southwest Power Pool, Inc., 106 FERC 61,254 (2004) ( March 19 Order )); and WHEREAS, as the FERC recognized in the March 19 Order, the LGIP and pro forma LGIA set forth in Order No do not allocate responsibilities between transmission owners and transmission providers for the provision of Interconnection Service and suggested that SPP and the SPP Transmission Owners enter into any agreement to allocate those responsibilities. NOW THEREFORE, SPP and the Transmission Owners that have executed this agreement agree to the following allocations of responsibilities: I. DEFINITIONS. Unless otherwise defined herein, all capitalized terms shall have the meaning set forth in the SPP Tariff. II. TERM OF AGREEMENT. This Agreement shall become effective as of January 20, 2004, and shall remain in effect until the FERC allows SPP s Order No Compliance Filing as it may be amended or revised or any subsequent filing that includes an allocation of responsibilities

37 with regard to Generator Interconnection Procedures and Interconnection Agreement to take effect. III PROVISIONS FOR ALLOCATION OF RESPONSIBILITIES BETWEEN SPP AND THE TRANSMISSION OWNERS. 1.0 Interconnection Service: The Parties recognize that the Transmission Provider will provide Interconnection Service pursuant to applicable terms of the SPP Tariff, and in particular, the Provisions of Attachment V, Standard Large Generator Interconnection Procedures and Agreement, as such provisions may be amended from time to time. Interconnection Service provides for the interconnection of the Interconnection Customer s Generating Facility with the Transmission System. The Parties also recognize that while SPP is the Transmission Provider under the SPP Tariff, SPP does not own any Transmission Facilities, and Transmission Owners own the facilities to which Large Generation Facilities are to be interconnected, and that the Transmission Owners may construct or modify facilities to allow the interconnection. While the Parties recognize that the Transmission Provider will be primarily responsible for undertaking Interconnection Studies and similar studies, and for transmission planning, Transmission Owners will be allowed to participate in these studies and activities to the extent consistent with the terms of the SPP Tariff [and bylaws and membership agreement], and with Commission policy. The Parties also recognize that construction activities and other construction-related matters may involve and be negotiated by the Transmission Provider, the applicable Transmission Owners, and by the Interconnection Customer. SPP shall not enter

38 into any Interconnection Agreement with an Interconnection Customer that is contrary to these rights. 2.0 Conflicts Between Agreements: In the event of any conflict between provisions of this Agreement and an individual Interconnection Agreement entered into between SPP and an Interconnection Customer, the provisions of that individual Interconnection Agreement shall control. 3.0 Transmission Owners Right to Participation in Studies, Committees and Meetings: 3.1 In the event that an Interconnection Customer proposes to interconnect a Large Generation Facility with a Transmission Owner s facilities, or a Transmission Owner is an Owner of an Affected System, that Owner shall have the right to participate in any Interconnection Facilities Study, Interconnection Feasibility Study, Interconnection System Impact Study, or any other study undertaken in connection with such request for Interconnection Service, to the extent necessary to facilitate such Interconnection. Such Transmission Owner or Owners shall also have the right to be a party to any Interconnection Facilities Study Agreement, Interconnection Feasibility Study Agreement, Interconnection System Impact Study Agreement, or any other agreement to perform studies, to the extent necessary to facilitate such Interconnection. 3.2 In the event that an Interconnection Customer proposes to interconnect a Large Generation Facility with a Transmission Owner s facilities, or a Transmission Owner is an Owner of an Affected System, that Owner shall

39 have the right to participate in the following committees and meetings established pursuant to the SPP LGIP and/or pro forma LGIA: the Joint Operating Committee, Scoping Meetings. 4.0 Performance Standards: Each Party shall perform all of its obligations under the Large Generator Interconnection Procedures and Interconnection Agreement in accordance with Applicable Laws and Regulations, Applicable Reliability Standards, and Good Utility Practice, and to the extent a Party is required or prevented or limited in taking any action by such regulations and standards, such Party shall not be deemed to be in Breach of the Interconnection Agreement for its compliance therewith. If such Party is the Transmission Provider or Transmission Owner, the Interconnection Agreement shall be amended and submitted to FERC for approval. K:\SPP\ALLOCATION AGREEMENT

40 SCHEDULE 4 -A Generation Imbalance Service Generator Obligations. For a generating station in a Control Area, but not dispatchable by that Control Area ("Generator"), Generation Imbalance Service is provided when a difference occurs over a single hour between the scheduled and the actual delivery of energy between the Generator and the Control Area for transactions that cross Control Area boundaries. Generator shall use commercially reasonable efforts to avoid the creation of any imbalance. The Transmission Provider shall not impose both a Schedule 4 charge and a Schedule 4-A charge on the same transaction within a host Control Area; provided, however, that when one or more schedules from the same generator (one or more generators with jointly metered output) are being delivered to more than one load entity (load) within the host Control Area, the Generator must provide a breakdown or allocation of the actual output of the generator to be credited to each load. If the Generator fails to provide such breakdown within 3 business days after the end of the month, the Transmission Provider and/or host Control Area Operator shall allocate the actual output in proportion to the original schedules and settle imbalances separately for the Generator and for each load in accordance with Schedule 4 or Schedule 4-A as appropriate. Separate settlements for the Generator and loads shall not be considered as imposition of impose both a Schedule 4 and Schedule 4-A charges if such action results from the failure of the Generator to provide the required output allocation within the specified time period. In the event that the Generator operates in a separate Control Area or the Generator s output is dynamically scheduled out of the Transmission Owner's Control Area to another Control Area and the equipment and related telemetry necessary to accomplish such dynamic scheduling is operational, then Generation Imbalance Service shall not apply. The Generator must either purchase this service from the Transmission Provider or make alternative comparable arrangements to satisfy its Generation Imbalance Service obligation. Unless the Generator makes alternative comparable arrangements, the Transmission Provider will obtain this service from the host Control Area or elsewhere, where appropriate, and the Generator shall pay the Transmission Provider for this service when the Transmission Provider provides this service to the Generator. In satisfaction of this obligation, an appropriate agent or customer of the 1

41 Generator (e.g., its power marketer(s) or customers(s)) may make prior contractual arrangements for the assumption of the responsibility for this service. The Transmission Provider will offer this service subject to its determination of the Transmission Owner's or Control Area operator s ability to maintain system reliability and to serve other commitments that exist at the commencement of the hour. In the event that the Transmission Provider determines during any hour that this service cannot be provided due to Transmission Owner's or Control Area operator s need to maintain system reliability and/or to serve prior commitments, the Transmission Provider shall on a nondiscriminatory basis adjust Generator's schedules as necessary, and provide the Generator with as much notice of such adjustment as is reasonably possible. Generator shall respond promptly to Transmission Provider's directions to make such schedule adjustments, pursuant to NERC requirements. If the Generator intends to rely on other arrangements to avoid imbalances, the Generator must demonstrate, to the Transmission Provider's reasonable satisfaction, that it has satisfied the requirements of this Schedule 4-A prior to the submission of any schedules for delivery from the Generator. In the event that the Generator fails to demonstrate to the Transmission Provider that the Generator has otherwise satisfied the requirements of this Schedule 4-A, the Generator shall be deemed to have elected to take Generator Imbalance Service under this Schedule 4-A. Charges. Charges for Generation Imbalance Service shall be calculated pursuant to Schedule 4 of the SPP OATT; provided, however, that if the Transmission Owner of the host Control Area providing the service has an applicable rate for Generation Imbalance Service on file with the Commission, the Generator shall pay the Generation Imbalance Service charge of such Transmission Owner. Charges to the Generator are to reflect only a pass-through of the costs charged to the Transmission Provider by the host Control Area operator or other suppliers. The Transmission Provider shall pass through the revenues it receives for this service to the Control Area operator or other suppliers providing the service. In calculating charges for Generation Imbalance Service pursuant to Schedule 4 of the SPP OATT, Generator's scheduled deliveries of energy at the Point of Interconnection with the host Control Area shall be adjusted for ramping, which shall be in accordance with NERC Policy 3, when such schedules are compared to the integrated values for the hours affected by such ramping. 2

42 ATTACHMENT AA TRANSMISSION SERVICE PREPAYMENT(Experimental) 1.0 Transmission Service Prepayment This Attachment allows Transmission Customers to make Transmission Service prepayments for the Transmission Provider s use in expanding the Transmission System. The total individual Transmission Customer prepayment shall be capped at the greater of either $50,000 or the largest monthly aggregate charge paid by the Customer for services under Schedules 7 and 8 during the prior 6 months. Transmission Customers must have had at least $50,000 in total charges during the prior calendar year to participate. 2.0 Treatment of Service Prepayment The Transmission Provider shall use the prepayment made to improve the transmission system. The Transmission System improvements made shall relieve constraints that limit shall be based on upgrading Available Transfer Capability. The Transmission Provider shall maintain a list of system upgrades that would improve Available Transfer Capability. The Transmission Customer can designate the system upgrades for which the service prepayment is requested to be used or allow the Transmission Provider and the Transmission Owners to determine which system upgrades to complete first. The Transmission Provider shall direct the Transmission Owner to construct the determined system upgrades. The Transmission Provider and the Transmission Owner will coordinate the timing, costs, payment schedule and conditions for the upgrade. The Funds provided by the Transmission Customer under this procedure shall be deposited in an escrow account. 3.0 Transmission Service Credit for Prepayment The Transmission Customers who make a prepayment shall receive future credit for transmission services provided under Schedules 7 and 8. The credit shall be provided at the same time and in the same amount as expenditures are made from the escrow account for the upgrades. If construction expenditures have not been made, the crediting shall begin

43 one year after the date of receipt. The Transmission Customer shall receive a credit on all portions of schedule 7 and 8 service that do not already provide for system upgrades. This shall continue on a monthly basis until the Transmission Customer has received full credit back for the amount of prepayment made. Transmission Customers shall receive interest on the balance in the escrow account. 4.0 Experiment Description This Transmission Service Prepayment Procedure is hereby implemented on an experimental basis and may be terminated one year after its effective date; except that credits for prepayments will continue until such time as the Transmission Customer has been completely reimbursed. In the course of the experiment, SPP will assess the merit of continued offering of this service.

44 SPP Presentation Analysis of the Wolverine and FP&L Orders SPP Regional Transmission Working Group April 8, 2004 Dallas, TX Presented by: Jeffrey W. Price, SPP Staff 2 1

45 Introduction The Wolverine Order and the FP&L Order address two separate tests designed by FERC: The seven factor test and the network integration test. The tests are distinct and address two issues: the definition of transmission and the integration of facilities into a transmission system. However, the tests are related because a seven factor analysis reduces the issues that would need to be discussed in the network integration analysis. 3 Introduction Analysis of FERC Order 888 and the Seven Factor Test Analysis of Wolverine Order Summary of Wolverine Analysis of FP&L Order Summary of FP&L Additional Information on the Network Integration Test Conclusion 4 2

46 Seven Factor Test In Order 888, The Commission proposed seven indicators of local distribution to be evaluated on a case-by-case basis: 1. Local distribution facilities are normally in close proximity to retail customers. 2. Local distribution facilities are primarily radial in character. 3. Power flows into local distribution systems; it rarely, if ever, flows out. 4. When power enters a local distribution system, it is not reconsigned or transported on to some other market. 5. Power entering a local distribution system is consumed in a comparatively restricted geographical area. 6. Meters are based at the transmission/local distribution interface to measure flows into the local distribution system. 7. Local distribution systems will be of reduced voltage. 5 Seven Factor Test We will defer to recommendations by state regulatory authorities concerning where to draw the jurisdictional line under the Commission's technical test for local distribution facilities, and how to allocate costs for such facilities to be included in rates, provided that such recommendations are consistent with the essential elements of the Final Rule. Moreover, we recognize that in some cases the Commission's seven technical factors may not be fully dispositive and that states may find other technical factors that may be relevant. We will consider jurisdictional recommendations by states that take into account other technical factors that the state believes are appropriate in light of historical uses of particular facilities. F.E.R.C. Order 888, 61 F.R. 21,540 at 21,

47 Wolverine Order Facts Wolverine is a cooperative completely surrounded by METC. Wolverine requested that MISO accept them as a Transmission Owner and set up a separate pricing zone. The original tariff required that a change in pricing zones could only be effectuated by a merger or acquisition and the new TO operated a control area on or before the date of the original filing. According to the proposed MISO agreement, Wolverine must have been a transmission provider before MISO was established and it "is or would have been a specified zone for pricing under an existing or proposed regional transmission tariff." 7 First Wolverine Order FERC examined the MISO Tariff language and determined that Wolverine did not meet the requirements for forming a separate pricing zone. Wolverine was never a control area and was not a separate pricing zone under any tariff. FERC decided that multiple owners in a single pricing zone can and should divide the revenue among them. The only mention of the 7 factor test in the original order was contained in the conclusion. FERC stated, We agree with the protesters that Wolverine's transmission facilities must meet the requirements of the seven factor test, as interpreted by the Michigan Commission, in order to ensure that Wolverine receives compensation for its transmission facilities on a basis comparable to the compensation received by Michigan Transco. 8 4

48 Second Wolverine Order Wolverine submitted a study completed by GDS that claimed all 138kV, 69kV, and 44kV non-radial lines were performing a transmission function. METC submitted a study that pointed to only two specific lines that performed a transmission function. The Michigan Public Service Commission (MPSC) reviewed METC s study and agreed with its conclusion based on an earlier MPSC seven factor test that it had used to separate METC s transmission facilities from its distribution facilities. FERC agreed with the METC study because we believe the conclusion reached in classifying Wolverine s facilities is comparable to the conclusion reached when the Michigan Commission classified the METC facilities. FERC did note, however, that The seven factor test as interpreted in the GDS study may be appropriate under different circumstances; however we reiterate that comparability of facilities is the key factor here because the relevant facilities are part of a joint pricing zone and not a single pricing zone. 9 MPSC s Application of the Seven Factor Test All 345 kv, 138 kv, and 120 kv facilities were classified as transmission because they easily fell within the seven factors with two exceptions: 1. Facilities used to connect generators to the 345kV or 138kV grid should not be considered transmission kv radial lines that flow energy to 138 kv/46 kv or 138 kv/23 kv step-down transformers, and distribution substations as well as those serving large customers directly. The true debate occurred in the classification of the 46 kv system. The cooperatives that were involved argued that these facilities should be considered transmission because they did not fit within factors 2-5 and 7 of the seven factor test. 10 5

49 MPSC s Application of the Seven Factor Test The MPSC considered each factor separately Factors 1 and 6: Neither factor was mentioned by the cooperatives so the MPSC treated both of them as a concession. Factor 2: Although the many 46 kv lines were looped, the MPSC found that the system operated as the functional equivalent of a radial system. Factor 3: The MPSC found that almost all power flowed into the 46 kv system. Factor 4: The MPSC interpreted markets as wholesale markets not just local markets so the 46 kv system did not meet this factor. Factor 5: The MPSC found that the length of the lines and distance that power flowed indicated a distribution system. Factor 7: The MPSC found that lower voltage lines are typically distribution. 11 Summary of Wolverine FERC deferred application of the seven factor test to the MPSC. The MPSC used the same analysis of the seven factors for both the METC system and the Wolverine system. FERC decided that comparability was the key factor, not just satisfying the seven factors. 12 6

50 FP&L Order Background Florida Municipal Power Administration (FMPA) filed a complaint in 1993 against Florida Power and Light (FP&L) alleging that FP&L should provide transmission service FMPA and its members. The Commission issued FMPA I, which the load ratio pricing method proposed by FP&L. The load ratio method allocates the costs of FP&L s transmission system between FP&L and FMPA based on the relative size of FP&L s and FMPA's loads that are served by network transmission service. However, in FMPA I the Commission also stated that if FMPA has transmission facilities that will operate as part of the integrated transmission system, a credit would be reasonable. 13 FP&L Order In FMPA II, FERC found that FMPA's facilities were not integrated with the transmission system of FP&L, and that, therefore, a credit was not appropriate. The test that FERC used was the integration test found in section 30.9 of the pro forma tariff: For a customer to be eligible for a credit, its facilities must not only be integrated with the transmission provider's system, but must also provide additional benefits to the transmission grid in terms of capability and reliability, and be relied upon for the coordinated operation of the grid. FERC found that the transmission facilities of most FMPA members are interconnected with the FP&L transmission system at single points that are used only to transfer power between the FP&L transmission system and each FMPA member's transmission system. FERC also found that FMPA facilities are not used by FP&L to provide transmission service to FMPA or any other party. Nor are they used to transmit FP&L s power to its non-fmpa customers. 14 7

51 FP&L Order In the latest order issued December 16, 2003, FERC directed direct FP&L to make a compliance filing, within 90 days of the date of this order, of a proposed rate schedule which does not include those FP&L facilities that fail to meet the same integration test applied to FMPA facilities in the TX Case. The compliance filing should identify, as to those FP&L facilities whose costs were included in the rates which were objected to by FMPA, why they should be included in the rates and why they are or are not comparable to FMPA s facilities. FERC did NOT use the seven factor test to determine whether FMPA facilities should be integrated into FP&L s transmission system. 15 Summary of the FP&L Order FMPA facilities were not considered as integrated facilities in FP&L s transmission system because they did not satisfy the Section 30.9 Network Integration Test. The FP&L order did not use the seven factor test to separate transmission from distribution. The correct parallel to draw between the FP&L order and the Wolverine order is the importance placed on comparability by FERC. 16 8

52 Additional Information on the Network Integration Test In the SPP RTO Order, FERC also references the network integration test laid out in the Consumers case. The Consumers case is very similar to the FP&L Order, but the ALJ in Consumers goes into more detail about the network integration test. 17 Additional Information on the Network Integration Test The following elements would appear necessary to satisfy a claim for credit based on integration: The network customer must demonstrate that the facilities for which it seeks credit are integrated into the plans and operations of the transmission provider to serve its power and transmission customers. The transmission provider is able to provide transmission service to itself or other transmission customers over the network customer's facilities. Actual use of a network customer's facilities by the transmission provider to provide service to the network customer or other parties. The network customer must show that its facilities provide additional benefits to the transmission grid in terms of capability, reliability and are relied upon for coordinated operation of the grid. 18 9

53 Additional Information on the Network Integration Test The Commission has also provided guidance as to what will not satisfy the integration standard: Interconnection of a network customer's facilities with those of the transmission provider alone is not enough to prove integration. The fact that the network customer's facilities serve a transmission function on the customer's side of the interconnection point is not enough to prove integration. The fact that a network customer's line constitutes a parallel path and is subject to parallel loop flows does not compel a conclusion that the line operates as part of an integrated network. Unnecessary redundancy provided by a network customer's facilities cannot qualify for a credit. 19 Conclusion The Wolverine Order is directly applicable to the definition of transmission because it explains the seven factor test designed by FERC. The FP&L Order will assist in developing an approach to resolving crediting issues but does not directly define transmission. The Consumers decision helps clarify the FP&L Order and the network integration test

54 Contact SPP Jeffrey W. Price General Inquiries: