EX-99.D71 3 c24752_exd7-1.txt Exhibit D-7-1 July 24, 2001 Mr. David P. Boergers Secretary Federal Energy Regulatory Commission 888 First Street, N.E. Washington, D.C. 20426 Re: American Electric Power Company, Inc., Docket No. ER01- -000 Dear Mr. Boergers: American Electric Power Company, Inc. ("AEP"), on behalf of itself, the AEP Operating Companies,(1) American Electric Power Service Corporation ("AEPSC"), AEP Generating Company ("AEG"), and certain new subsidiaries of AEP, files the attached initial and amended rate schedules under Section 205 of the Federal Power Act ("FPA"), 16 U.S.C. ss. 824d (1994). As explained herein, this filing is necessary to implement the restructuring requirements in Ohio and Texas, where AEP Operating Companies have previously provided retail electric generation service under state cost-of-service regulation. These restructuring programs open retail electric generation service to competition and require the separation of the generation function from transmission and distribution functions. The restructurings in Ohio and Texas are part of a continuing movement toward further competition in the electric power industry, a movement that AEP has supported at both federal and state levels. Separation of AEP's generation that serves Ohio and Texas from the traditional utility transmission and distribution functions brings this generation fully into the wholesale generation market and thereby serves state restructuring objectives. The separation of the generation and wires businesses, together with the development of Regional Transmission Organizations ("RTOs") encouraged by this Commission, will enhance the creation of a robust wholesale electricity market that provides efficiencies that will benefit all consumers and provide the basis for the successful restructuring of retail electricity markets in Ohio, Texas, and other states. This filing is part of AEP's ongoing effort to advance the competition process.(2) AEP will continue these efforts through its leadership in the development of RTOs, its advocacy before federal and state policymakers, and its active cooperation in state efforts to restructure retail markets. This filing is designed to comply fully with the Ohio and Texas restructuring programs, and yet to maintain to the extent feasible the existing balance of benefits and obligations among those Operating Companies that either will continue to provide retail electric service under traditional cost-of-service regulation in other states or are not yet authorized to undergo corporate separation. To achieve these objectives, AEP must amend certain agreements, terminate one agreement, and enter into new agreements, as described below. AEP seeks FERC acceptance of the amendments, termination, and new agreements so that they may take effect on January 1, 2002.(3) AEP has begun the process of discussing these proposed changes with state regulatory commissions in the jurisdictions where retail electric generation service remains regulated. Because AEP is not certain that it will be able to complete this process and resolve all issues by the time that responses to this submittal are due, AEP believes that the most efficient manner of proceeding is for the Commission to designate a settlement judge and to initiate settlement proceedings as described in Section XIV below. I. Background A. Description of the AEP System Before Restructuring The AEP Operating Companies provide retail electric service in eleven states - Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia, and West Virginia. The AEP System, which took its present form after the merger between AEP and Central and South West Corporation ("CSW") effective June 15, 2000, is comprised of two parts - "AEP-East," consisting of the pre-merger AEP operating companies, and "AEP-West," comprised of the pre-merger CSW operating companies. In each part of the AEP System, coordination agreements among operating companies have permitted the integrated dispatch of the Operating Companies' generation and some degree of sharing of generation capacity and of the benefits of centralized purchasing of energy and power from third parties. These agreements - the AEP-East Interconnection Agreement and the AEP-West Operating Agreement - differed in significant detail, but both were based on the premise that the participants in the agreements were vertically integrated public utilities engaged in providing retail electric service within defined service areas and subject to state cost-of-service regulation in the provision of that service. B. Status and Effects of State Restructuring The states in which the AEP Operating Companies provide retail service have reached different decisions on whether, when, and how to restructure their electricity industries. Two of the states - Ohio and Texas - have deregulated generation, mandated corporate separation, and eliminated the concept of native load retail service in favor of free and open competition at retail. The AEP Operating Companies that have previously provided retail electric generation service in Ohio and Texas must achieve corporate separation of their generation function from their transmission and distribution functions. The affected AEP Operating Companies are Ohio Power Company ("OPCO") and Columbus Southern Power Company ("CSP") in Ohio and Central Power and Light Company ("CP&L"), West Texas 2 Utilities Company ("WTU"), and Southwestern Electric Power Company ("SWEPCO") in Texas. These requirements necessitate several actions that are subject to the approval of this Commission. Contemporaneously with this filing, AEP is submitting an application under Section 203 of the FPA for the transfers of jurisdictional assets that are required to accomplish the corporate separations in Ohio and Texas and the related corporate restructuring. In this filing pursuant to Section 205 of the FPA, AEP submits the following rate schedules: 1. A Restated and Amended AEP-East Interconnection Agreement ("Interconnection Agreement") (Attachment 1)(4) among the three remaining vertically integrated AEP-East Operating Companies - Appalachian Power Company ("APCO"), Indiana Michigan Power Company ("I&M"), and Kentucky Power Company ("KPCO") - that will continue to provide retail electric service in states that either are not restructuring or have not mandated legal corporate separation. The amendments will permit those companies to continue the mutually beneficial coordination of their operations without the participation of OPCO and CSP. 2. A Restated and Amended AEP-West Operating Agreement ("Operating Agreement") (Attachment 2) that will permit Public Service Company of Oklahoma ("PSO") and SWEPCO to continue to coordinate their operations without the participation of the WTU, CP&L, and without that portion of SWEPCO's generation subject to the Texas corporate separation requirements. 3. A Restated and Amended System Integration Agreement ("SIA") (Attachment 3) that reflects the restructuring and resulting non-participation of the Ohio and Texas companies. 4. A Unit Power Sales Agreement ("SWEPCO UPSA") (Attachment 4) between SWEPCO and an AEP subsidiary, Power Marketing Affiliate ("PMA"), that assigns to PMA the part of SWEPCO's generating capacity that is associated with SWEPCO's retail native load in Texas and its wholesale contracts.(5) A companion Second Unit Power Sales Agreement ("Second Agreement") (Attachment 5) will provide SWEPCO with access to a proportionate share of the capacity received by PMA under the SWEPCO UPSA needed by SWEPCO to continue supplying its existing wholesale contract customers for the remaining terms of their respective contracts. In addition, if retail restructuring is limited or delayed in SWEPCO's territory because of delay in certification by the Public Utility Commission of Texas ("PUCT") of SWEPCO's region as a "qualifying power region" under the Texas law,(6) the Second Agreement will enable SWEPCO to have access to an appropriate share of the capacity received by PMA under the SWEPCO UPSA so that, in such event, SWEPCO and the SWEPCO-affiliated Retail Electric Provider ("SWEPCO REP") can fulfill any continuing "provider of last resort" obligations under Texas state law. 5. A Unit Power Sales Agreement between OPCO and PMA ("OPCO UPSA") (Attachment 6) for most of OPCO's generation capacity. 3 6. A Unit Power Sales Agreement between CSP and PMA ("CSP UPSA") (Attachment 7) for most of CSP's generation capacity. 7. An Operating Agreement among OPCO, APCO, and AEPSC with respect to the Philip Sporn generating plant ("Sporn Operating Agreement") (Attachment 8) that recognizes that part of the generation (OPCO's portion, to be assigned to PMA), will be committed to the competitive wholesale market, while the remainder (APCO's portion) will be used by APCO to fulfill its public utility responsibility subject to state cost-of-service regulation. 8. An Operating Agreement among OPCO, APCO, and AEPSC with respect to Unit No. 3 of the John E. Amos generating plant ("Amos Operating Agreement") (Attachment 9) that recognizes that part of the generation (OPCO's portion, to be assigned to PMA), will be committed to the competitive wholesale market, while the remainder (APCO's portion) will remain subject to state cost-of-service regulation. 9. An Operating Agreement among I&M, KPCO, AEP Generating Company ("AEG"), and AEPSC with respect to Units 1 and 2 of the Rockport Steam Electric Generation Station ("Rockport Operating Agreement") (Attachment 10) that facilitates the dispatch of that portion of the plant's capacity that has been freed for competition. 10. In addition, AEP provides notice and an agreement to terminate the Interim Allowance Agreement ("IAA") (Attachment 11) among the AEP-East Operating Companies, an agreement that has provided a mechanism for allocating among those companies the benefits and costs of Clean Air Act emissions allowances. The new and amended agreements and the agreement to be terminated, together with the reasons for each action, are described below. AEP will take other steps to respond to the imperatives of state restructuring while remaining in compliance with applicable federal law. These steps will include establishing separate and independent dispatch and merchant functions for regulated and deregulated generation, with the regulated merchant organization charged with minimizing the cost of power through off-system sales and purchases. II. The Restated and Amended AEP-East Interconnection Agreement A. Existing Provisions of the AEP-East Interconnection Agreement The AEP-East Interconnection Agreement, originally entered into on July 6, 1951, is an agreement among the AEP-East Operating Companies, under which the individual generation resources of the participating companies ("Members") are dispatched on a single-system basis, and the costs and benefits of generation resources are shared on a system-wide basis. The agreement provides for meeting system energy requirements on a least-cost basis from among available resources. AEPSC, acting as Agent for the Members, dispatches energy on an economic basis, assigning the highest incremental cost to off-system sales. Each Member meets its requirements initially out of its own generation to the extent dispatched, and 4 thereafter through primary purchases from affiliates. The Interconnection Agreement prices such purchases at the delivering Member's average cost of generation for the month. Revenues from off-systems sales are initially allocated to the Member providing the generation dispatched for each sale up to the amount of its generation costs for the sale. Above that point, the Members share net revenues from such sales on the basis of the Member Load Ratio ("MLR") - the ratio of each member's Non-Coincident Peak ("NCP") load over the latest twelve-month period to the sum of NCP loads for all Members over the same period. Likewise, the Agent makes energy purchases on a system basis and apportions the cost by MLR to Members. The Interconnection Agreement also contains a capacity equalization mechanism to levelize capacity investment imbalances among the AEP-East companies as they rotate construction of new generation. Each participating company bears its proportionate share of the system's total capacity and reserves based on the MLR. The "deficit" members make capacity payments to the "surplus members" based on the surplus member's weighted average embedded costs of investment in its non-hydroelectric generating plant expressed on a per kilowatt per month basis plus associated fixed operating costs.(7) However, the capacity equalization formula does not equalize the costs of capacity investment between "long" (capacity-surplus) and "short" (capacity-deficit) companies.(8) B. Description of Changes in the Restated and Amended AEP-East Interconnection Agreement The primary change in the Restated and Amended Interconnection Agreement is the withdrawal of OPCO and CSP as Members and, therefore, as participants in the energy exchange arrangements. This change is clearly in the public interest. As the Commission's Trial Staff recognized in addressing a similar issue involving the Entergy Corporation System Agreement, the "disparity of goals" between deregulated generation companies and regulated Operating Companies means that their respective generation assets can no longer be dispatched on a joint basis, "[n]or can the original members of the System Agreement continue to plan for the future together."(9) In the case of the AEP Interconnection Agreement, the restructuring legislation in Ohio has fundamentally altered the relationship between OPCO and CSP and the remaining regulated Operating Companies. OPCO and CSP will no longer have an obligation to serve native load at cost-based rates from their generation, and such generation will be both deregulated and disaggregated to participate in an efficient wholesale bulk power market. The Interconnection Agreement, under these circumstances, would result in inappropriate cost shifting and would impede the development of competition. The existing Interconnection Agreement provides for the exchange of energy in excess of that required to supply a Member's native load. The elimination of native load requirements in Ohio would produce distorted and unfair results under the existing agreement.(10) 5 Retail competition can create stranded costs for the former regulated companies. In most cases, the deregulated companies can recover such stranded costs only through the revenues they receive from sales. If a deregulated entity is required to share its generation resources with still-regulated Operating Companies, its opportunity to recover stranded costs as contemplated in retail access programs will be drastically diminished. The Commission has cautioned strongly against such cost shifting that results from the differing pace of deregulation in different states.(11) If the existing provisions of the Interconnection Agreement remained unchanged, the other Members would be required to pay OPCO and CSP very large capacity equalization charges, because all of the OPCO and CSP generation would be in excess of a (non-existent) native load. Whether it gained or lost, each of the Members would experience effects that would be aberrational and unrelated to the purposes of the Interconnection Agreement. In addition, continued OPCO and CSP membership in the Interconnection Agreement would impose untoward burdens on Ohio consumers and Ohio's deregulated market. The most economical generation in Ohio, which should be available to compete for sales in the market, would be lost to the market because the remaining regulated Members would have a pre-emptive call on it. Likewise, the ability of AEP's wholesale marketing arm to participate in the wholesale market would be substantially curtailed by the unpredictability of its obligation to supply energy from deregulated generation resources to the remaining regulated Members. FERC has held that the Interconnection Agreement requires Members to supply sufficient capacity to meet their native load requirements over time.(12) That interpretation of the Agreement suggests that companies without a native load obligation should not be required to supply capacity. Moreover, since the purpose of the Interconnection Agreement is to combine the capacity of the individual Members to serve their combined native loads, the Interconnection Agreement has no useful purpose with respect to Members that have no native load. The Restated and Amended Interconnection Agreement makes other substantive changes. First, the provisions for capacity equalization payments among the remaining participating companies are being eliminated. The states that are served by the remaining participating companies - APCO, I&M, and KPCO - are addressing restructuring on different schedules. Virginia and Michigan are moving forward with restructuring, while Kentucky, Indiana, and West Virginia appear not to be, at least in the near future.(13) Consequently, it is appropriate to plan future capacity additions in a manner that recognizes that the status of one or more of the remaining participants in the Agreement is likely to change, and that the concept of "rotating construction" no longer appropriately applies under these circumstances. Further, the increasingly deregulated market for wholesale energy has made capacity additions a less urgent priority. While in 1951 it could be anticipated that persistent capacity shortfalls would be met by new construction, an operating company may now rationally choose to meet a portion of its capacity and energy needs through purchases for an extended period of time without the construction of new capacity. It is more appropriate for the decision 6 to acquire new capacity to be made in light of the assessment of future needs in a state and that state's likely future determination with respect to whether and when to deregulate. Second, energy purchases from other Members will be priced at the midpoint between the Seller's Incremental Cost and the Purchaser's Decremental Cost.(14) These provisions will better balance the opportunity to make off-system sales with the obligation to serve the energy needs of a member company. Third, the formula for allocating the proceeds of off-system energy sales is proposed to be changed. The hourly net margins for such sales will be shared in proportion to each Member's generation for sales (including economy sales), less its economy purchases from other members (but not less than zero). This approach will permit a more accurate assignment of the benefits to those members providing such generation resources. This change will also conform practice in AEP-East to that in AEP-West. The structural changes that AEP proposes to effect for Ohio and Texas are required by state law, and AEP believes that it is not obligated at shareholder expense to insulate its Operating Companies in states that have not restructured from the effects of restructuring in Ohio and Texas. Nevertheless, AEP's cost studies demonstrate that the transition to an amended Interconnection Agreement with a "three-company system," incorporating the changes described above as well as the changes in the System Integration Agreement described below, should be possible without adverse economic impact on any of the three Operating Companies (APCO, I&M, and KPCO) that either will continue to provide service to native load customers in unrestructured jurisdictions or have not yet authorized corporate separation. In addition, the existence of some form of retail rate freeze in most of the states in which AEP operates provides further assurances that retail consumers will not be affected significantly by adoption of the Restated and Amended Interconnection Agreement. AEP's studies compare the payments and receipts that each of the remaining Operating Companies would experience under the current agreement and under the agreement, as revised, after withdrawal of OPCO and CSP. They show that the effect of the proposed changes on the three remaining AEP-East Operating Companies will be, in each case, a small reduction in for the 2002-2004 period as compared with projected costs under the current agreements.(15) III. The Restated and Amended AEP-West Operating Agreement A. Existing Provisions of the AEP-West Operating Agreement The AEP-West Operating Agreement provides for integrated economic dispatch of the member companies' generation. AEPSC, acting as Agent for the AEP-West Operating Companies, performs the dispatch. Each Member meets its requirements first through its own generation to the extent dispatched and second, if economy energy is available, from purchases from other Members. Such purchases are priced on a split-the-savings basis between the buyers' and the sellers' costs if the buyers have capacity available. Pool energy is used mainly to avoid committing units. The Operating Agreement assigns the generation resource with the highest 7 incremental cost to off-system sales. There are no routine capacity payments among the members, but the Agreement provides for the possibility of capacity sharing when a Member is surplus by more than a 15 percent planning reserve margin (no such sharing is currently in effect). The current Operating Agreement nets off-system sales and off-system purchases. The Members share hourly margins on off-system sales in proportion to each Member's generation for sales less its economy purchases from other Members for that same hour (but not less than zero). Hourly margins on off-system purchases are shared in proportion to each Member's reduced generation for purchases less any economy sales to other Members for that same hour (but not less than zero). B. Description of Changes in the Restated and Amended AEP-West Operating Agreement The Restated and Amended Operating Agreement for the remaining AEP-West Operating Companies will closely resemble the Restated and Amended Interconnection Agreement for the remaining AEP-East Operating Companies. As in the case of the Interconnection Agreement, the primary change in the Operating Agreement is the withdrawal of those Members that are undergoing restructuring and corporate separation of their generation functions - WTU, CP&L, and the portion of SWEPCO's generation attributable to its Texas retail load. As is the case in AEP-East, and for the same reasons, this change for AEP-West is clearly in the public interest. The Texas companies will no longer have native load obligations. If they were to continue to participate in the arrangement, the other participants would have first call on all of their generation, defeating the purposes of deregulation in Texas and imposing excessive burdens on Texas consumers. To the extent that the most economic deregulated generation is burdened with obligations under the Operating Agreement, the intent of the Texas restructuring legislation may be frustrated. Finally, the call on Texas generation under the existing Operating Agreement would impede and distort the efforts of the deregulated companies to recover stranded costs, as permitted by the Texas restructuring legislation. The Restated and Amended Operating Agreement makes several other substantive changes going forward. First, the provisions for joint planning of future generation capacity and provisions for capacity sharing among the participating companies are being modified so that the planning function recognizes and takes account of possible restructuring in any of the two remaining jurisdictions. Oklahoma, served by PSO, has enacted legislation to plan for deregulation but has so far not implemented any plan. Arkansas has enacted deregulation but has deferred the effective date. Planning of future capacity additions must take account of the likelihood that deregulation will proceed - or not - on a state-by-state basis, and not system-wide. In the future, it may be preferable for the regulated operating companies to rely on the market for needed capacity and energy rather than to commit to construction of new resources. Second, energy purchases from other Members will be priced at the midpoint between the seller's incremental cost and the purchaser's decremental cost.(16) These provisions will more correctly reflect the economic costs of the options available to a Member, while permitting the use of the most economic energy by the Members. 8 Third, the hourly net margins for off-system energy sales will continue to be shared in proportion to each Member's generation for sales, but (as in the East) that generation will include economy sales. Economy purchases from other members will continue to be subtracted from the allocation, with the result not less than zero. Again, AEP's cost studies show that PSO and SWEPCO can effectively operate a "two-company system," incorporating the changes described above as well as the changes in the System Integration Agreement described below, without material adverse economic impact on their native load customers. The overall effects for years 2002-2004 are de minimis. See Attachment 12. There are small cost reductions for PSO; SWEPCO shows a small cost increase in the initial years, moving to a small decrease by 2004. IV. The Restated and Amended System Integration Agreement A. Existing Provisions of the System Integration Agreement The System Integration Agreement ("SIA") was developed in the context of the AEP-CSW merger to govern the integration and coordination of the power supply resources of the merged AEP Operating Companies. The SIA provides for the distribution of power supply costs and benefits between the AEP-East and AEP-West zones. It functions in addition to, but not in substitution for, the existing AEP-East Interconnection Agreement and the AEP-West Operating Agreement, which continue to govern the distribution of costs and benefits within the zones. The SIA provides for coordinated planning and operation among vertically integrated, regulated Operating Companies. Its provisions contemplate integrated planning and development of power supply resources on a combined system basis to integrate the zones and maximize efficiency, reliability and cost effectiveness. The SIA also provides ground rules for economic dispatch of the combined system's generating resources and establishes the ground rules for capacity and energy exchanges and emergency response between the zones. The agreement contemplated combined system dispatch on a least-cost basis, but each zone's most economic generation used to serve its native load and previously committed firm load contracts.(17) Under the SIA, off-system sales and trading margins above an historic base level (the twelve (12) months preceding the merger) are shared according to the ratio of owned generating capacity in the two zones. B. Description of Changes in the Restated and Amended System Integration Agreement The primary change in the Restated and Amended System Integration Agreement is the withdrawal of the deregulated companies - OPCO, CSP, CP&L, and WTU. For the same reasons discussed earlier, it no longer is appropriate in the inter-zone arrangements for the deregulated companies to integrate and coordinate their power supply resources with the regulated Operating Companies. The deregulated generation companies and the remaining Operating Companies have disparate goals; having them continue to coordinate and integrate their power supplies would cause inappropriate cost-shifting and impede competition. 9 The other principal change in the Restated and Amended System Integration Agreement is that non-physical trading and marketing will not be part of the coordinated activities of the parties. The Agreement, however, will continue to provide for centralization of off-system purchases and off-system sales. This is consistent with AEP's overall objective of charging the regulated merchant organization with minimizing the cost of power through off-system sales and purchases. In addition, the Restated and Amended System Integration Agreement provides that off-system sales margins will be shared in proportion to owned generating capacity in the two zones. This change will eliminate the historic threshold for the sharing of benefits between the West and East Zones. In light of the departure of the Ohio and Texas Operating Companies from the System Integration Agreement (as well as from their respective system agreements), elimination of the previous threshold provides a better mechanism for the sharing of benefits between the East and West Zones.(18) V. The Unit Power Sales Agreements Between SWEPCO and PMA A. Description of the SWEPCO UPSA In order to comply with the Texas requirement to separate the generation function from transmission and distribution functions, SWEPCO proposes to enter into a Unit Power Sales Agreement ("SWEPCO UPSA") with PMA and AEPSC. Effective January 1, 2002, SWEPCO will separate its existing generation capacity into SWEPCO-assigned capacity (representing that portion of SWEPCO's generation attributable to the continued regulated requirements of Louisiana and Arkansas retail customers) and PMA-assigned capacity (representing that portion of SWEPCO's generation attributable to its current Texas retail native load and its wholesale requirements load). Under Texas law, the former capacity must be operated in the wholesale market on a deregulated basis and may not be sold directly to Texas retail customers. The assignment of capacity to PMA will be based on the ratio of the sum of the demands of the SWEPCO-Texas retail native load and the SWEPCO wholesale contract native load at the time of the four Year 2000 coincident monthly summer (June through September) SWEPCO peak demands to the sum of the same four coincident peak demands of the total SWEPCO native load. This approach proportionally assigns rights to the capacity in SWEPCO's generating units between SWEPCO's deregulated and regulated operations and thereby facilitates the onset of competition in Texas and at the same time reasonably maintains the status quo for the states that have not enacted restructuring statutes. SWEPCO will continue to own, operate, and maintain its power plants and its assigned capacity will continue to be dispatched by AEPSC, which has performed this function since the merger of CSW with AEP. B. Description of the Second Agreement There will also be a Second Unit Power Sales Agreement ("Second Agreement") among PMA, SWEPCO, and AEPSC, the purpose of which will be to provide SWEPCO with 10 access to a proportionate share of the Assigned Capacity received by PMA under the SWEPCO UPSA so that SWEPCO can continue supplying its existing wholesale contract customers for the remaining terms of their respective contracts. The proportion of PMA's Assigned Capacity to be assigned to SWEPCO under the Second Agreement will be based on the ratio of the sum of the four coincident peak demands of native load for each wholesale contract to the sum of the same four coincident peaks demands of the total SWEPCO native load. Because SWEPCO's wholesale contracts expire or may terminate at different times, the proportion of PMA's Assigned Capacity that is assigned to SWEPCO under the Second Agreement will change as each wholesale contract expires or is terminated. A portion of the monthly costs that SWEPCO charges to PMA will be netted out based on the share of capacity that is assigned to SWEPCO during that month and the energy dispatched from SWEPCO out of the capacity assigned under the Second Agreement. C. Contingent Provisions The Second Agreement also provides for two sets of contingencies related to retail restructuring under the Texas Public Utility Regulatory Act, Chapter 39 of Title 2 of the Texas Utilities Code ("PURA"): First, if the PUCT has not certified the "power region" in which SWEPCO is located as a "qualifying power region" pursuant to the terms of section 39.152(a) of PURA at the time that retail customer choice begins, the SWEPCO REP will have a continuing obligation under section 39.202(m) of PURA to serve certain large customers at rates that are no higher than the rates that, on a bundled basis, were in effect on January 1, 1999, subject to certain adjustments provided for in section 39.202(m) of PURA. At this time, the PUCT has not yet certified the SPP (SWEPCO's region) as a "qualifying power region" under the Texas statute. Second, pursuant to section 39.103 of PURA, if the PUCT determines that a power region is unable to offer fair competition and reliable service to all retail customer classes on January 1, 2002, it shall delay customer choice for the power region, in which case SWEPCO would continue to have a public utility obligation to serve Texas retail customers at cost-based rates. To address these contingencies, the Second Agreement also provides that PMA will assign back to SWEPCO a proportionate share of the Assigned Capacity it receives under the SWEPCO UPSA so that SWEPCO can furnish part of the resources needed for the SWEPCO REP to fulfill the obligations imposed under section 39.202(m) of PURA, or if the PUCT delays retail customer choice in SWEPCO's territory, that PMA will assign back to SWEPCO a proportionate share of the Assigned Capacity it receives under the SWEPCO UPSA so that SWEPCO can continue to furnish regulated electric service. As in the case of the wholesale contracts, to the extent that the statutory obligations are reduced or eliminated, the assignment back from PMA to SWEPCO will decrease by a corresponding percentage. VI. Unit Power Sales Agreement between OPCO and PMA 11 OPCO's restructured generation will be free to enter the wholesale market. In order to consolidate deregulated wholesale marketing, AEP submits herewith a Unit Power Sales Agreement between OPCO and PMA that assigns to PMA all of OPCO's generating capacity except that portion to be used to serve OPCO's remaining wholesale contracts. VII. Unit Power Sales Agreement between CSP and PMA As in the case of OPCO, CSP's restructured generation will be free to enter the competitive wholesale market. Accordingly, AEP submits herewith a Unit Power Sales Agreement between CSP and PMA that assigns to PMA all of CSP's generation capacity except that portion to be used to serve CSP's remaining wholesale contracts. VIII. Philip Sporn Generating Plant Operating Agreement OPCO and APCO each owns units at the Philip Sporn Generating Plant. Pursuant to the Ohio restructuring, OPCO's portion of the plant's generating capacity will no longer be subject to state cost-of-service regulation; that generation will be assigned to PMA pursuant to the OPCO-PMA Unit Power Sales Agreement described above. With that change, APCO and OPCO will be subject to different regimes - market forces in OPCO's case, cost-of-service regulation in APCO's case. The Sporn Operating Agreement submitted with this filing contains provisions which permit OPCO and APCO independently to communicate their dispatch schedules to the plant operator. IX. John E. Amos Unit No. 3 Operating Agreement As with the Sporn plant, AEP submits herewith an Operating Agreement with respect to Unit No. 3 of the John E. Amos Generating Plant (jointly owned by OPCO and APCO) that recognizes that OPCO's portion of the generation (to be assigned to PMA under the Unit Power Sales Agreement described above), will be in the competitive wholesale market, while APCO's portion will remain subject to state cost-of-service regulation. The purposes and provisions of the agreement are similar to those of the Sporn Operating Agreement. X. Rockport Steam Electric Generation Station Operating Agreement AEG owns fifty percent of the generating capacity of Units 1 and 2 of the Rockport Steam Electric Generation Station. Until recently, part of AEG's capacity had been subject to a long-term sale to an unaffiliated utility. That sales contract has now expired, and the subject AEG generation will be free to participate in the competitive wholesale market. Accordingly, AEP submits herewith an Operating Agreement among I&M, KPCO, AEG, and AEPSC with respect to Units 1 and 2 of the Rockport Steam Electric Generation Station. The purposes and provisions of the agreement are similar to those of the Sporn and Amos Operating Agreements described above. XI. Termination of the Interim Allowance Agreement A. Description of the Interim Allowance Agreement 12 APCO, I&M, KPCO, OPCO, and CSP (with AEPSC as Agent) entered into the AEP System Interim Allowance Agreement ("Interim Allowance Agreement") in 1994 to allocate Clean Air Act emission allowances associated with transactions undertaken by or on behalf of these AEP-East Operating Companies pursuant to the AEP-East Interconnection Agreement.(19) At the time of the Interim Allowance Agreement, there had been little experience with such emission allowances and it was unclear how to allocate such allowances among the AEP-East Operating Companies for different types of transactions, such as economy energy sales or off-system sales. The Interim Allowance Agreement provided a mechanism for such allocation arrived at through consultation by the AEP-East Operating Companies and state regulatory authorities. B. Reasons for Termination of the Interim Allowance Agreement The Restated and Amended AEP-East Interconnection Agreement includes the cost of emissions allowances as part of the incremental costs of the AEP-East Operating Companies used for purposes of establishing pricing for economy energy purchases among these companies and for off-system sales. The margins on off-system sales under the Restated and Amended AEP-East Interconnection Agreement are allocated on the basis of generation, not load as under the initial Interconnection Agreement. This enables the AEP-East Operating Companies to be compensated for the cost of emissions allowances in proportion to the generation of energy associated with off-system sales. The AEP-East Operating Companies have adopted this approach on the basis of their experience with emissions allowances over the past several years. It also reflects, and facilitates, the transition to a competitive energy market. With allocation of emissions allowances now dealt with in the Restated and Amended AEP-East Interconnection Agreement, there is no need for a separate Interim Allowance Agreement for this purpose. Therefore, the Interim Allowance Agreement will be terminated. XII. Request for Limited Waivers from the Requirements of Order Nos. 888, 889 and 2000 As the result of the corporate separations of generation described herein, AEP's deregulated generation subsidiaries will own and control all or a part of the generator step-up transformers and leads and related circuit breakers and other protective equipment at their respective generating stations. These limited and discrete facilities, which are classified as transmission facilities for purposes of the Commission's Uniform System of Accounts, do not form a part of the integrated interstate transmission network. Should any of the deregulated generation subsidiaries receive a request for transmission service with respect to these facilities, it will file an open access transmission tariff within 60 days after the date the request is received and comply with any additional requirements that are effective as of that date. In similar circumstances, the Commission has granted waivers from the requirements of Order Nos. 888 and 889.(20) AEP requests that its deregulated generation subsidiaries be afforded similar relief. 13 In addition, AEP requests waiver of the requirements of Order No. 2000 with respect to the facilities to be owned by the deregulated generation subsidiaries. AEP submits that the public interest does not require that generating companies that own only limited and discrete transmission facilities be required to participate in regional transmission organizations ("RTOs") as transmission owners, or be subject to any disparate rate treatment otherwise applied to owners of integrated interstate transmission facilities that do not join RTOs. XIII. Other Information Required by Section 35.13 Because the instant filing does not involve a rate increase within the meaning of section 35.13(a)(2)(iii) of the Commission's regulations, 18 C.F.R. ss. 35.13(a)(2)(iii) (2000), AEP provides, to the extent not already provided elsewhere in this Transmittal Letter, the following information required by sections 35.13(b) and (c), 18 C.F.R. ss. 35.13(b), (c) (2000): * Amendments to the AEP-East Interconnection Agreement, the AEP-West Operating Agreement, and the System Integration Agreement and red-lined versions of the amended agreements are provided at Attachments 1, 2 and 3. * A description of the various Agreements submitted herewith and the reasons for filing are discussed in the body of this Filing. * No expenses or costs in connection with this filing are illegal, duplicative, or unnecessary within the meaning of 18 C.F.R. ss. 35.13(b)(7). * Tables comparing of the costs shared under the current AEP-East Interconnection Agreement, the AEP-West Operating Agreement, and the System Integration Agreement and the proposed Amendments for the period 2002-04 are included in Attachment 12.(21) * A draft notice of filing suitable for publication in the Federal Register is provided at Attachment 13, and an electronic copy has also been provided on a diskette. * A list of names and addresses of persons to whom a copy of the filing has been sent is included as Attachment 14. XIV. Request for Initiation of Settlement Procedures AEP recognizes that this filing proposes significant changes in the structure and operation of the AEP System, and that state commissions and other parties will wish to examine carefully the proposed new and amended agreements contained in this filing. At the same time, AEP believes that most if not all of the policy issues raised by this filing can be resolved through discussion in the context of a Commission-sponsored settlement proceeding. Similar procedures worked well in the recent Cinergy Services, Inc. proceeding,(22) and also (post-hearing) in the Louisiana Public Service Commission v. Entergy Services, Inc. proceeding.(23) Accordingly, AEP respectfully requests that the Commission appoint a settlement judge, after the close of the period provided for comments and interventions, and thereafter move 14 directly to a settlement conference. Such a conference will, at a minimum, narrow and define and differences among the stakeholders that remain for Commission resolution; and, at best, it may lead to resolution of the entire proceeding through settlement. XV. Persons Designated to Receive Service and Correspondence Edward J. Brady Kevin F. Duffy American Electric Power Service Corporation 1 Riverside Plaza Columbus, Ohio 43215 614-223-1617 - voice 614-223-1687 - fax ejbrady@aep.com kfduffy@aep.com J. A. Bouknight, Jr. Douglas G. Green Steptoe & Johnson LLP 1330 Connecticut Avenue, NW Washington, DC 20036-1795 202-429-3000 - voice 202-429-3902 - fax jbouknight@steptoe.com dgreen@steptoe.com Clark Evans Downs Shelby L. Provencher Jones, Day, Reavis & Pogue 51 Louisiana Avenue, NW Washington, DC 20001 202-879-3939 - voice 202-626-1700 - fax cedowns@jonesday.com slprovencher@jonesday.com XVI. Conclusion For the reasons stated above, AEP requests that the Commission permit the submitted rate schedules to become effective, subject to refund, on January 1, 2002. Respectfully submitted, AMERICAN ELECTRIC POWER SERVICE CORPORATION 15 By: Edward J. Brady J. A. Bouknight, Jr. Kevin F. Duffy Douglas G. Green American Electric Power Steptoe & Johnson LLP Service Corporation 1330 Connecticut Avenue, N.W. 1 Riverside Plaza Washington, DC 20036-1795 Columbus, Ohio 43215 202-429-3000 - voice 614-223-1617 - voice 202-429-3902 - fax 614-223-1687 - fax Clark Evans Downs Shelby L. Provencher Jones, Day, Reavis & Pogue 51 Louisiana Avenue, N.W. Washington, DC 20001 202-879-3939 - voice 202-626-1700 - fax Submitted: July 24, 2001 (1) Appalachian Power Company, Columbus Southern Power Company, Central Power and Light Company, Indiana Michigan Power Company, Kentucky Power Company, Kingsport Power Company, Ohio Power Company, Public Service Company of Oklahoma, Southwestern Electric Power Company, West Texas Utilities Company, and Wheeling Power Company. (2) AEP has previously filed to transfer control of its transmission facilities to the Alliance and Southwest Power Pool ("SPP"), is supporting the implementation of the Alliance RTO on schedule, and will advocate and support the SPP's facilitating a larger regional transmission marketplace, as the Commission has recommended. (3) To the extent necessary, AEP respectfully requests waiver of the Commission's notice requirements under Section 35.3(a) of the Commission's regulations, 18 C.F.R. ss. 35.3(a) (2000), so as to permit the submitted rate schedules to go into effect as of January 1, 2002. (4) Red-lined versions are included with the Interconnection Agreement, Operating Agreement and SIA. (5) The appellation "PMA" is used as a placeholder with the name of the power marketing affiliate to be determined and substituted before the agreement is executed. (6) See Public Utility Regulatory Act, Tex. Util. Code Ann. ss. 39.152(a) (Vernon 1998 & Supp. 2001). (7) See Kentucky Power Co., 37 FERC para. 63,015 at 65,170-71 (1986), aff'd in part and modified in part, Opinion No. 266, 38 FERC para. 61,243, order on reh'g, Opinion No. 266-A, 39 FERC para. 61,158 (1987). (8) The Interconnection Agreement assigns any capacity purchases to the most capacity-deficit Member. (9) Commission Trial Staff's Initial Brief in Louisiana Public Service Comm'n v. Entergy Services, Inc., Dkt. Nos. EL00-66-000 et al. at 8 (Apr. 5, 2001). (10) AEP intends to comply with the corporate separation requirement in Ohio by transferring transmission and distribution facilities out of OPCO and CSP. (11) See Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, [1991-1996 Regs. Preambles] FERC Stats. & Regs., Regulation Preambles, para. 31,036 at 31,826 (1996). (12) See AEP Generating Co. and Kentucky Power Co., 38 FERC para. 61,243 (1987). (13) Virginia has adopted restructuring legislation, and proceedings are pending before the Virginia State Corporation Commission regarding the implementation of restructuring, including the issue of corporate separation of generation. West Virginia enacted restructuring legislation, but its implementation has been postponed. Michigan has enacted legislation that contemplates a transition to retail choice, but has not as yet authorized or required corporate separation of generation. (14) "Decremental cost," for this purpose, is usually the lower of the incremental cost of generation or the applicable market price. However, if the buyer's native load is in excess of its available generation, "decremental cost" will be the market price. 15) The results of the study are provided in Attachment 12. (16) As in the case of the Interconnection Agreement, "decremental cost" is the lower of the incremental cost of generation or market price. When the purchaser's native load is in excess of its available generation, "decremental cost" will be the market price. (17) AEPSC acts as agent for the Operating Companies to coordinate planning and design or purchase of new power supply resources, operation and maintenance of generating units, economic dispatch, centralized trading and marketing, acquisition and provision of transmission services for inter-zone power transfers, billing, and administration. (18) Other minor changes have been made to reflect the fact that (1) the AEP and CSW merger became effective on June 15, 2000, and (2) that Central and South West Services, Inc. merged into AEPSC as of January 1, 2001. (19) The Commission accepted the Interim Allowance Agreement for filing by letter order dated December 30, 1994, Docket No. ER 94-1670-000. The Commission accepted for filing Modification No. 1 to the AEP System Interim Allowance Agreement by letter order dated August 30, 1996 in Docket No. ER 96-2213-000. (20) See, e.g., Public Service Co. of New Mexico, 93 FERC, para. 61,213 (2000); Niagara Mohawk Power Corp., 89 FERC, para. 61,124 (1999); Jersey Central Power & Light Co., 87 FERC, para. 61,014 (1999). (21) As noted, the proposed amendments to the AEP East Interconnection Agreement, the AEP-West Operating Agreement and the System Integration Agreement will not take effect until January 1, 2002. AEP is submitting studies comparing payments and receipts that each of the remaining Operating Companies would experience under the current and amended rate schedules for each of the years in the 2002-04 period. This is the most relevant and meaningful period for which to perform revenue comparison studies because it coincides with when the amended rate schedules initially take effect. Moreover, these Agreements constitute a "zero-sum game" such that AEP recovers no net revenues in any year, and this remains true under the proposed amendments. Accordingly, to the extent necessary, AEP respectfully requests waiver of any further comparison statement under Section 35.13(c). (22) Cinergy Services Inc., Dkt. No. ER01-200-000. (23) See Explanatory Statement in Support of Offer of Settlement in Louisiana Public Service Commission & City of New Orleans v. Entergy Services, Inc. et al., Dkt. No. EL00-66-000 (June 15, 2001).